Petroleum Engineering Manual

Engineering Training Manual

Updated Dec. 1999

TABLE OF CONTENTS

BASIC HYDROCARBON RESERVOIRS

1.0 HOW HYDROCARBON RESERVES ARE TRAPPED

2.0 HOW HYDROCARBON RESERVES ARE FOUND

3.0 HOW HYDROCARBON RESERVES ARE PRODUCED

DRILLING SYSTEMS

1.0 CATEGORIZATION OF DRILLING

2.0 ROTARY DRILLING OPERATIONS

3.0 DRILLING PLAN

4.0 OFFSHORE DRILLING

WELL COMPLETION

1.0 CASING DESIGN AND CONNECTORS

2.0 WELLHEADS - PLATFORM AND SUBSEA

3.0 TUBING PACKERS

4.0 DOWNHOLE SAFETY VALVES

SUBSEA TREES AND CONTROLS

1.0 CATEGORIZATION OF SUBSEA TREES

2.0 SUBSEA TREE COMPONENTS

3.0 CONTROL SYSTEMS

PIPELINES

1.0 CATEGORIZATION OF PIPELINES

2.0 DESIGN OF PIPELINES

3.0 INSTALLATION OF PIPELINES

4.0 PIPELINE OPERATIONS

FLUID PROPERTIES AND PRODUCTION

1.0 INTRODUCTION

2.0 HYDROCARBON PHASE BEHAVIOR

3.0 FLUID FLOW IN PIPING

4.0 OPERATIONAL CONSIDERATIONS


Updated Dec. 1999

TABLE OF CONTENTS (Cont’d)

PRODUCTION FACILITIES

1.0 INTRODUCTION

2.0 DESCRIPTION OF VARIOUS COMPONENTS

WELL OPERATIONS

1.0 INTRODUCTION

2.0 WELL PRODUCING NEEDS

3.0 WELL FLOWING CHARACTERISTICS

4.0 TUBING FLOW CONSIDERATIONS

5.0 THEORETICAL CONSIDERATIONS FOR VERTICAL TWO PHASE FLOW

6.0 “OPTIMUM” TUBING SIZE

7.0 CHOKE PERFORMANCE CURVES

8.0 GAS LIFT

9.0 WELL START-UP OF “KICK-OFF”

10.0 WELL MONITORING

11.0 WELL KILLING

12.0 WELL WORKOVERS

13.0 ROUTINE WELL SERVICING

OFFSHORE MOORING AND LOADING SYSTEMS

1.0 HISTORICAL OVERVIEWS

2.0 TYPES OF MOORING SYSTEMS

3.0 RESTORING FORCE AND SYSTEM STIFFNESS

4.0 MOORING FORCE

MARINE SYSTEMS

1.0 THE SHIPSHAPE

2.0 STABILITY

3.0 MOTION

4.0 MODEL TESTS

5.0 CLASSIFICATION SOCIETIES


Updated Dec. 1999

BASIC HYDROCARBON RESERVOIRS

TABLE OF CONTENTS

1.0 HOW HYDROCARBON RESERVES ARE TRAPPED................................................................ 1

1.1 Geologic Time............................................................................................... 1

1.2 Rock Types .................................................................................................. 1

1.3 Depositional Environments ............................................................................. 2

1.4 Porosity and Permeability .............................................................................. 2

1.5 Structure and Hydrocarbon Traps .................................................................... 2

2.0 HOW HYDROCARBON RESERVES ARE FOUND.................................................................... 3

2.1 Geophysical Data.......................................................................................... 3

2.2 Physical Samples ......................................................................................... 3

2.3 Logs............................................................................................................. 3

2.4 Production History ......................................................................................... 3

2.5 Subsurface Mapping ...................................................................................... 4

2.6 Reserve Estimating........................................................................................ 4

3.0 HOW HYDROCARBON RESERVES ARE PRODUCED............................................................. 5

3.1 Well Testing.................................................................................................. 5

3.2 Material Balance ........................................................................................... 5

3.3 Fluid Flow in Porous Media ............................................................................ 6

3.4 Primary Recovery Drive Mechanisms for Oil Reservoirs ..................................... 6

3.4.1 Dissolved Gas Drive ................................................................................. 6

3.4.2 Water Drive ............................................................................................. 8

3.4.3 Gas Cap Drive ......................................................................................... 9

3.4.4 Combination Drive................................................................................... 10

3.5 Primary Recovery Drive Mechanism for Gas Reservoirs .................................... 11

3.6 Secondary Recovery Drive Mechanism’s......................................................... 12

3.6.1 Waterflooding......................................................................................... 12

3.6.2 Gas and Water Injection.......................................................................... 13

3.7 Tertiary Recovery.......................................................................................... 13

3.7.1 Miscible Methods ................................................................................... 13

3.7.2 Thermal Methods ................................................................................... 14

3.7.3 Improved Waterflood Methods .................................................................. 14


Updated Dec. 1999

LIST OF FIGURES

FIGURE 1. Geologic Time

FIGURE 2. Basic Rock Types

FIGURE 3. Depositional Environment

FIGURE 4. Porosity

FIGURE 5. Permeability

FIGURE 6. Variations of Horizontal and Vertical Permeabilities

FIGURE 7. Structural Traps

FIGURE 8. Salt Dome Traps

FIGURE 9. Seismic Survey

FIGURE 10. Seismic Record

FIGURE 11. Physical Basis of Well Logging

FIGURE 12. Subsurface Maps

FIGURE 13. Estimation of Total Reserves

FIGURE 14. Well Testing

FIGURE 15. Material Balance

FIGURE 16. Darcey’s Law

FIGURE 17. Oil Reservoir Depletion Characteristics

FIGURE 18. Dissolved Gas Drive Reservoirs

FIGURE 19. Water Production Problems

FIGURE 20. Gas Cap Drive Reservoirs

FIGURE 21. Gas Production Problems

FIGURE 22. Combination Drive Reservoir

FIGURE 23. Volumetric Gas Reservoir

FIGURE 24. Advantage of Early Waterflood Initiation

FIGURE 25. Waterflood

FIGURE 26. Water and Gas Injection

FIGURE 27. New Recovery Methods


Updated Dec. 1999

1.0 HOW HYDROCARBON RESERVES ARE TRAPPED

The most generally accepted explanation for the origin of petroleum is the organic theory. This theory

presumes that the hydrogen and carbon that make up petroleum come from plants and animals living on

land and in the sea.

1.1 Geologic Time

The study of geologic history helps explain and predict oil and gas accumulations. Geologic time is

measured in millions of years, and has been divided by tectonic or climactic changes which are usually

evidenced by changes in the environment and its inhabitants as shown in Figure 1. The absolute dating of

formations by nuclear isotope analysis is possible, but the sequence and correlation of formations and

events are much more important. Stratigraphy and paleontology are used to establish the sedimentary

history. Stratigraphy is the study of the formation, composition, sequence, and correlation of rock units.

Paleontology is the study of fossil remains in search of their life cycle, environment, evolution and age.

Paleontology is used extensively in petroleum geology because the fossils can be recovered from drill

cuttings.

1.2 Rock Types

Sedimentary rocks form 99+% of the world’s petroleum reservoirs. They are rocks formed by the

accumulation of mineral and organic material (sediment) in water or from air. Sedimentary rocks are

grouped in two categories-- (1) clastics, and (2) carbonates and evaporities.

Clastics are formed from the physical and chemical breakdown of preexisting rocks when deposited in new

arrangements after being moved by water, air, or ice. They are classified based primarily on composition

and grain size. Sandstones are mostly quartz grains from .05 to 2 mm in diameter. Shales, clays, and

muds are characterized by extremely small particle size and are important in both sourcing and sealing

hydrocarbon reservoirs. Shales form the bulk of the volume of sediment in the world.

Carbonates and evaporites are formed in place by biological and chemical action. Limestones are usually

formed by biologic activity such as coral reefs. Most of the Middle East production is from limestones.

Other examples are dolomite and salt.

The two other rock types, besides sedimentary, are igneous and metamorphic as summarized on Figure 2.

They are rarely reservoir rocks. Igneous rocks are formed by the colling and consolidating of complex

siliceous solutions from a molten or partially molten state, for example, granite and basalt. Metamorphic

rocks are formed when high temperature and/or pressure alter pre-existing rocks; examples are quartzite,

marble, and slate.


Updated Dec. 1999

1.3 Depositional Environments

Reservoirs are characterized by their depositional environment. Tectonism affect the relief, the energy, and

the rate of composition. Eroded rock types affect resulting sediment composition. Climate affects

weathering transport, vegetation and sea level. The physical, biologic, and chemical environment causes

different rock types, reservoir geometries, and facies. Facies are lateral subdivisions based on contrasts in

appearance, composition, biology, environment, or reservoir quality within a stratigraphic time equivalent

unit. Examples of depositions, as shown in Figure 3, are alluvial fans, deltas, beaches, barrier reefs, and

atolls.

1.4 Porosity and Permeability

Two rock properties which are important in understanding how hydrocarbons accumulate are porosity and

permeability. Porosity, as defined in Figure 4, is the percent of the rock volume which is void space. This

space is filled in the subsurface with water and hydrocarbons. Permeability, as defined in Figure 5, is a

measure of the ability of a rock to transmit fluids. Permeability may vary by direction in the same rock, as

shown in Figure 6. A permeable rock must be porous because the fluid moves through interconnected

pores. However, a porous rock may not be permeable if the pores are isolated. Generally, the greater the

porosity, the greater the permeability.

1.5 Structure and Hydrocarbon Traps

Sedimentary rocks are usually deposited in relatively flat units or planes. Movements of the earth’s crust

will bend, break, uplift, or downwarp these sedimentary units. This dramatically affects sedimentation on

the surface and geometry in the subsurface. Synclines are regional downwarping which attracts sediments

as the rivers run downhill. Anticlines are “hills” formed in the sedimentary units by vertical uplifting and

folding. Faulting is caused by shearing forces which break the sedimentary units. Examples of these

structural system are shown in Figure 7. Salt domes are the result of salt beds pushing up towards the

surface as shown in Figure 8.

As previously discussed, sedimentation produces the source material for the hydrocarbons, the reservoir,

and the seal (impermeable shales). Digenesis, or change due to heat, pressure, and mineral rich solutions

generates the hydrocarbon and alters the reservoir by compaction, chemical solidification, and other

physical changes such as channeling and fracturing. Structuring frequently forms or increases the closure

necessary to trap the hydrocarbons and prevent them from continuing to migrate updip. The hydrocarbon

traps may be formed during deposition, i.e., stratigraphic traps, or later due to structural movement


Updated Dec. 1999

2.0 HOW HYDROCARBON RESERVES ARE FOUND

Exploration geologists must understand the regional geologic picture to find new oil and gas fields. Once a

new field has been discovered, and its commerciality determined, production geologists and reservoir

engineers must find and define the individual reservoirs within the field. The production geologists and

reservoir engineers must find and define the individual reservoirs within the field. The production geologists

and reservoir engineers coordinate the drilling of all necessary development wells to economically deplete

the field.

2.1 Geophysical Data

Geophysical data, for example seismic, is used to find hydrocarbon reserves. In seismic systems, a source

of high acoustic energy creates sound waves which reflect off the individual subsurface layers as shown in

Figure 9. The resulting record shown in Figure 10, provides a profile of subsurface structure. It can indicate

structures which are favorable for trapping hydrocarbons, and also the presence of hydrocarbons

themselves. Exploration geologists always rely on geophysical data before drilling an exploratory well to

verify the prediction.

2.2 Physical Samples

Physical samples from drilled wells provide information which can indicate the presence of hydrocarbons or

allow prediction of where it may be found. Core analysis allow prediction of where it may be found. Core

analysis allows assessment of lithologic facies, reservoir quality, and presence of hydrocarbons. Drill

cuttings can indicate the presence of hydrocarbons and provide fossils for paleontologists to study.

2.3 Logs

Logs are considered the basis for modern petroleum geology. They are a record of a tool run in the hole

which measures certain formation properties and they allow very reliable qualitative and quantitative

evaluations as summarized in Figure 11. One of the most important functions they serve is clear definition

of the formations and other strata which allows subsurface mapping of reservoirs. Other logs can verify the

presence of hydrocarbons and allow calculation of critical reservoir parameters such as porosity and water

saturation. These critical parameters are usually the basis for reserve estimates which can decide field or

reservoir development feasibility.

2.4 Production History

Well, reservoir, and field production histories can be useful tools for finding hydrocarbon reserves. This

technique would more often be used by production geologists and engineers, however, exploration


Updated Dec. 1999

geologists consider regional field production histories when assessing potential new fields. In existing fields

the production history is carefully monitored as it can indicate opportunities for additional reserves.

Normally production history is used in conjunction with subsurface mapping to predict new reservoirs.

2.5 Subsurface Mapping

The purpose of subsurface mapping is to diagram the geometry of formations or reservoirs, and thereby

enhance predictive ability. The correlation of well logs is the principal criterion used for constructing maps

and cross sections of petroleum reservoirs. Continuous, widespread deposits with consistent log

characteristics allow unit-by unit correlations. However, many stratigraphic units are erratic in both log

characteristic and spatial distribution. Correlation of these sections is best achieved by relating genetic

intervals of strata.

Contour mapping employs contour lines connecting points of equal value. Reservoir structure maps are

prepared where the contours represent lines of intersection between a series of parallel horizontal planes

(depth) and the non-horizontal reservoir top surface. The structure maps indicate the direction and angle of

the sloping surface. Structure types, such as anticlines, synclines, and faults can be read on the map.

Fluid contacts (i.e., gas-oil, gas-water, oil-water) are horizontal planes and are mapped like contours on a

structure map.

2.6 Reserve Estimating

After discovery of a new field, a reserve estimate must be made to determine the field’s commerciality. To

do this, the field limits are estimated based on available well control and seismic data. Isopach maps are

constructed so that the total rock volume of productive reservoir can be estimated based on areal extent and

thickness. Porosity and water saturation are calculated from logs. In-place reserves are then calculated

volumetrically by accounting for the rock porosity and connate water saturation. Figure 13 summarizes the

calculation of in-place reserves for gas and oil.

Recoverable reserves are assumed to be some percentage of the reserves in place. The recovery efficiency

is based on the expected recovery mechanism. This subject will be covered later.


Updated Dec. 1999

3.0 HOW HYDROCARBON RESERVES ARE PRODUCED

Hydrocarbons produce from a reservoir basically because of the pressure sink created by opening the well

to a surface gathering system. A more detailed understanding of how and why fluids move in the reservoir

can lead to optimum recovery of the reserves. The role of the reservoir engineer is to optimize reservoir

development by early and accurate determinations of reservoir size, drive mechanisms, and well

deliverabilities. The development drilling program and reservoir operating plan can then be effectively

implemented.

3.1 Well Testing

The productivity of a well can be estimated with well tests. The measure of well productivity is the

Productivity Index (PI) which is the ratio of production rate and the pressure drop driving the fluid from the

state reservoir to the well bore. The calculation is presented in Figure 14. The production is usually run

through a choke on the surface and test results are stated as a measure of well capacity for a particular

choke size. Other well tests are drawdown tests for measuring permeability and pulse tests using two wells

to measure formation communication.

3.2 Material Balance

The term “material balance” is so well accepted, it cannot be changed but the subject should more

accurately be called “volumetric balance.” Material balance is used to evaluated reservoir performance and

can lead to better reservoir descriptions and development plans.

When a volume of oil is produced from a reservoir, the space once occupied by this oil must be filled with

something else. Unless fluid is injected, the production of oil must result in a decline in reservoir pressure.

This pressure decline can cause the influx of fluids from an adjoining gas cap or aquifer, the expansion of

fluids originally in the reservoir, and the expansion of reservoir rock grains.

Consider an oil reservoir, where the original pore volume contains only oil and connate water. After some oil

has been produced, the pore volume can be divided into six discrete volumes to account for all the possible

ways that the produced oil space can be refilled. The six items are: (1) the expansion of an adjoining gas

cap; (2) The volume of gas released from oil; (3) the volume of oil still in the reservoir; (4) The expansion of

the reservoir rock grains; (5) the original connate water which has expanded; and (6) the influx of water from

an adjoining aquifer. Only item (3), (4), and (5) need to be considered in every oil reservoir. All the items

are graphical shown in Figure 15.

Gas form the gas cap will tend to occur near the top of the reservoir and water from the aquifer will generally

be near he reservoir base. Under some conditions, gas released from the oil will gravitate to the top of the


Updated Dec. 1999

reservoir. More often the released gas will be evenly distributed throughout the reservoir, as are the

expansions of rock and connate water.

3.3 Fluid Flow in Porous Media

Production of hydrocarbon reservoirs involves the movement of two immiscible fluid phases as one phase

displaces another through a porous medium. The fundamental law of fluid motion in hydrocarbon reservoirs

in Darcy’s law. This law, shown in Figure 16, pints out the dependence on the quantity of flow on the

pressure gradient, permeability, and the fluid viscosity.

For multiphase fluid flow, the permeability and pressure terms of Darcy’s law require additional explanation.

In general, the presence of one phase reduces the ease of flow for other phases. This leads to the concept

of relative permeability. Relative permeability to a given phase is defined as the effective permeability of that

phase, at a given saturation, divided by the single phase permeability. The nature of relative permeability

curves depends on local distribution of fluid within pores, which is controlled by capillary pressures.

Capillary pressures dominate local fluid distribution in all porous media, but may or may not be important in

a macroscopic displacement.

For the equations in this form, there is no analytical solution to describe the movement of oil and water.

Viscous, capillary, and gravitational forces all can be important in the displacement process. They can be

solved by computer using difference equation techniques.

When viscous and gravitational forces are much larger than capillary forces, the capillary forces can be

neglected. This allows the second-order partial differential equations to collapse to a first-order partial

differential equation. This resulting equation can be solved to give a so-called Buckley-Leverett

displacement. The Buckley-Leverett equation is an expression for the rate at which water saturations move

across a system when water is injected into one end of the system. A major use of the Buckley-Leverett

simplified displacement theory is in waterflood predictions.

3.4 Primary Recovery Drive Mechanisms for Oil Reservoirs

The drive mechanism of a reservoir normally refers to the principal source of energy available to expel the

hydrocarbon from the reservoir rock. The production schedule is influenced by the drive mechanism as

shown in Figure 17. Recovery from an oil reservoir is more complex than recovery from a gas reservoirs.

Many of the basic principles also apply to gas reservoirs. Gas reservoirs are briefly discussed later.

3.4.1 Dissolved Gas Drive

Dissolved gas drive (DGD) is the most common depletion mechanism; practically every reservoir that

experiences pressure decline will have some portion of its drive contributed by DGD. A DGD reservoir relies


Updated Dec. 1999

principally on the liberation and expansion of gas dissolved in the oil to supply the energy necessary to

displace the oil to the wellbore. This “dissolved gas” actually refers to light hydrocarbons which are liberated

as pressure declines due to production. Figure 18 illustrates this mechanism.

Normally a predominant DGD mechanism will be associated with closed or volumetric type oil columns. An

adjoining aquifer and /or gas cap will be small or non-existent.

DGD reservoir wells have a characteristic behavior during their producing life. As oil is produced from a well,

pressure drops in the immediate vicinity. This causes fluids to expand from out in the reservoir driving oil

toward the pressure sink. As reservoir pressure declines below the bubble point gas evolves from solution,

occurring as small separate bubbles in individual pore spaces. When enough gas is released such that

critical gas saturation is reached, relative permeability to gas exists, and gas begins flowing to he well along

with the oil.

This well behavior results in a characteristic reservoir performance during the producing life. The initial gas-

oil ration is the dissolved ration, and the gas-oil ration declines slightly until critical gas saturation is

reached. Once gas begins to flow, the gas-oil ration increases steadily. The reservoir pressure decline is

very rapid during the fluid the rock expansion phase above the bubble point pressure. The pressure declines

slowly after the bubble point is reached, then more rapidly as more and more gas is produced per unit of oil.

The most important characteristic is that oil recovery is low at abandonment pressure. It is far below the

recovery expected for the two other types of primary drive mechanisms; water drive or gas cap expansion.

Rock properties have the most important influence on DGD recovery. Relative permeability has the most

important effect, since this determines the critical gas saturation. In general, oil recovery increases as

absolute permeability and connate water saturation increases. Porosity has no effect on recovery efficiency.

Reservoir oil properties affect recovery, but to a lesser degree than rock properties. High solution gas-oil

ration results in low recovery because the oil shrinkage more than offsets the greater available displacing

action. Low oil recoveries also are obtained from reservoirs where oil viscosity is high. The high viscosity oil

tends to be bypassed by the low viscosity gas.

Gravity drainage is really a separate drive mechanism, but it is a part of all types of drive mechanisms. In

DGD reservoirs, it can have a profound effect on overall recovery. The driving force for gravity drainage is

simply the density difference between gas and oil. In thick or steeply dipping reservoirs, gravity can cause

oil to move downward if replaced by gas moving upward. Gravity drainage can result in much higher

recoveries and should be recognized early because the recovery may be rate-sensitive. DGD recovery is not

rate-sensitive.

In the absence of gravitational effects and competitive problems, oil recovery under DGD is independent of

well spacing. The optimum spacing should be determined based on an economic study which indicated the

optimum production rate. Location of the development wells should give consideration though to the


Updated Dec. 1999

potential need for future water injection wells.

Because of very low recovery, a pure DGD reservoir of any extent should be recognized early so that it can

be evaluated for application of a more efficient secondary drive mechanism. If adequate well control exists,

basic reservoir geology provides the earliest clues to the presence of a DGD reservoir. The DGD process is

associated with closed reservoirs formed by stratigraphic traps, fault traps, and structural traps. The

performance of nearby reservoirs and fields in a more advanced stage of depletion would also provide a clue.

As reviewed earlier, early production performance will offer evidence of DGD.

3.4.2 Water Drive

Water drive reservoirs are those in which the predominant source of energy for producing oil is water

encroachment from surrounding or underlying formations. For effective water drive a very large aquifer is

required to provide the expansion energy, because the water and rock are not very compressible. The

reservoir and aquifer must be reasonably permeable and continuous, and production rates must not greatly

exceed the rate at which the aquifer can supply water.

Reservoir performance is characterized by a high degree of pressure maintenance, high recovery efficiency,

low gas-oil ratios, and continuously increasing water cut. The original pressure is usually close to

hydrostatic head. Ultimate recoveries from water-drive reservoirs of 30-80% have been reported.

High production rates have potentially an important influence on performance and recovery. High rates may

(1) lower pressure rapidly causing DGD, increased oil viscosity, and excessive oil shrinkage, (2) reduce

gravity benefits, (3) prevent imbibition of water into tight zones, and (4) cause water coning and fingering as

shown in Figure 19. Although the high production rates may have quite an influence on early performance, it

has substantially less effect on ultimate recovery. This is because rate effects are reduced by typical long

periods of relatively low production rates as the reservoirs approach depletion.

Other factors influence recovery to a greater extent. Water-oil relative permeability dictates the residual oil

saturation in the water contacted areas. High permeability improves recovery, however, high permeability

layers in heterogeneous reservoirs can reduce recovery because water tends to channel through these

regions.

Water drive should be detected early so that development and producing operations can be tailored to take

maximum advantage of available energy. Wells should be located so as to remain uninvaded as long as

possible. Early detection can be achieved by observing static oil-water interface rise in observation wells,

and water cut behavior of producing wells near the reservoir periphery. Material balance calculations can

also indicate presence of a water drive.

Volumetric balance can be used to calculate water influx for the known history since pressure and

production are known. To predict future reservoir behavior, water influx must be determined independent of


Updated Dec. 1999

volumetric balance. For this an unsteady state solution of the radial diffusivity equation is used assuming a

constant terminal pressure. The equation, however, requires that the aquifer properties be evaluated

empirically from the history using volumetric balance. This is because aquifer properties are difficult to

evaluate individually. Water influx predictions can then be made for any given forecast of production rates for

oil, gas, and water.

Simultaneous solution of the volumetric balance and water influx equations is possible only for a stipulated

schedule of production. Independent equations or relationships are necessary to predict production rates

and ultimate recovery. The equations or relationships needed are those which describe the distribution of

oil, gas, and water in the reservoir in relation to the positions and completion depths of all wells drilled or to

be drilled. In general, an accurate determination of fluid distribution requires that the reservoir be treated in

at least two dimensions. Fortunately, meaningful answers can be obtained by approximating reservoir

behavior with simplifying assumptions in one dimension.

3.4.3 Gas Cap Drive

A gas cap occurs in a reservoir when more light hydrocarbons are present than can be dissolved in the oil.

The energy for producing oil is provided by the expansion of the gas cap into the oil zone as the pressure

drops as shown in Figure 20. DGD is always associated with gas cap drive.

Pressure drop in a gas cap drive reservoir is usually proportional to cumulative production unless excess

free gas is produced. The rate of pressure drop depends on the size of the gas cap and the oil zone. If the

cap is large compared to the oil zone, the pressure drop will be small. Producing gas-oil ratios (GOR)

remain low until the expanding gas cap invades upstructure producing wells through coning and fingering as

shown in Figure 21. High GOR wells should be shut-in or recompleted lower to prevent waste of the

reservoir energy.

Oil recovery from gas cap drive ranges from 25% to 60% of the oil in place. The requirements for an effective

gas cap drive are: (1) Large gas cap relative to the size of the oil zone; (2) Continuous uniform reservoir; and

(3) Good gravitational segregation characteristics such as high dip angle, high permeability, low oil viscosity,

and low production rate.

3.4.4 Combination Drive

Most reservoirs produce by a combination of the drive mechanisms as shown in Figure 22. In developing a

depletion plan for a combination drive reservoir, it is important to determine the degree to which each

mechanism is affecting oil displacement and recovery efficiency.

Response or reaction time of each drive mechanism must be considered in the analysis of a combination

drive reservoir. Gas cap drive has a quick reaction time and is very responsive to a pressure drop in the


Updated Dec. 1999

reservoir. This is due to the high expansive property and low viscosity of the gas and will result in rapid

movement of the gas-oil contact.

Water drive response is slow compared to gas cap drive and DGD. The factors which contribute to the slow

response are (1) its relative high viscosity compared to gas; (2) its low expansive properties; and (3) the

distance that the pressure transient must travel. DGD response is quick but limited because of the amount

of gas liberated and is tendency to be produced.

Reaction times explains why gas cap and/or DGD will usually dominate in early life and anytime oil zone

withdrawals are accelerated. Water drive will become important later in life after sufficient time to react to

the pressure drop. If gravity is effective, DGD becomes less important as released gas recharges the gas

cap and retards pressure drop.

Recovery efficiencies can be calculated from actual reservoir performance after a period of production history

has been experienced. This is done using portions of the volumetric balance equation. If there are

insufficient data to calculate displacement efficiencies from production data, the Welge equation can be

used to calculate theoretical displacement efficiencies. The Welge equation estimates the average

saturation of the displacing fluid behind the advancing front. It does include conformance or pattern

efficiency, which would have to be estimated from geologic data and well drainage pattern.

To improve reservoir performance, major reservoir problems must be recognized as soon as possible and

then steps should be taken to correct the problem. For example, gas cap shrinkage is one of the most

prevalent problems associated with multi-drive reservoirs. Shrinkage occurs when free gas production

exceeds the expansion of the gas cap. A loss in ultimate recovery occurs as a portion of the oil entering

the gas cap never be recovered.

Means of detecting gas cap shrinkage include: looking for high ration production while reservoir pressure is

constant or increasing; volumetric balance calculation; premature watering out of wells near the oil-water

contact; and nuclear logging programs for wells near the gas-oil contact. Means of arresting gas cap

shrinkage and improving reservoir performance include: initiating a gas injection program; shutting in high

ration oil wells: and increasing production rate if possible to cause a reduction in reservoir pressure and

permit gas cap expansion.

3.5 Primary Recovery Drive Mechanism for Gas Reservoirs

As with oil reservoirs, the type of drive mechanism that exists in a gas reservoir can aid in selection of

development and producing practices. The recovery efficiency in a volumetric gas reservoir is dependent on

the average pressure to which the reservoir can be lowered at abandonment. Unlike an oil reservoir, the

recovery efficiency of a gas field is usually greater if no water drive is present. The calculation recovery

efficiency is shown in Figure 23. Recovery efficiencies are generally in the range from 50% to 80% for water


Updated Dec. 1999

drive reservoirs and 80% to 95% for pressure depletion reservoirs. The main reasons for lower efficiencies in

water drive reservoirs are (1) encroaching water does not contact all of the reservoir: (2) in portions where

water does invade, some gas is left as residual gas saturation ranging from 15% to 35%.

In the case of gas reservoirs with effective water drive, the pressure will usually be maintained as water

sweeps through the reservoir. Ultimate recovery can be increased by producing the reservoir at a sufficiently

high rate to reduce

the pressure at abandonment to a low level. This is possible due to the response times relationship

between gas the aquifer. Strategic location of producing wells, of course, may increase ultimate recovery

significantly.

3.6 Secondary Recovery Drive Mechanism’s

Secondary recovery in hydrocarbon reservoirs refers to the injection of water and/or natural gas to increase

the ultimate oil recovery above that which would have resulted from primary recovery. Early recognition of

the need for secondary recovery will normally maximize ultimate recovery. Typically, secondary recovery is

implemented as part of the initial development plan, rather than after primary recovery has depleted the

reservoir.

3.6.1 Waterflooding

Waterflooding is most often used in reservoirs whose dominant primary recovery mechanism is dissolved

gas drive. The reservoirs would become pressure depleted before much of the oil is recovered. As shown in

Figure 24, water injection is an efficient method of maintaining reservoir pressure and sweeping the

recoverable oil to producing wells. The recovery of oil by waterflooding is a combined function of the

reservoir invaded and the displacement efficiency in the invaded area.

Reservoir properties and mechanics of waterflooding are not known in sufficient detail to allow rigid prediction

calculations. Reasonable predictions can be made with simplifying assumptions. The Buckley-Leverett

Theory is considered the best technique.

The most important controllable factor for an efficient waterflood project is the location of injection and

production wells to maximize areal sweep efficiency. Figure 25 shows several waterflood strategies. Areal

sweep efficiency is the fraction of the waterflood pattern area contacted by water at a given time. Production

streamlines develop between injectors and producers, and a straight line connecting them is the shortest

streamline and has the highest pressure gradient. Injected water moves more rapidly through the shortest

streamline and therefore reaches the producing wellbore when only a portion of the pattern area has been

contacted by water.

For optimum areal sweep efficiency, waterfloods are frequently conducted in repeated patterns such a 5-


Updated Dec. 1999

spot, line drive, inverted 9-spot, and others. For these common patterns, much experimental and theoretical

work has been conducted to determine the most efficient waterflood patterns for given applications. In these

studies, pattern efficiency is usually expressed by curves as a function of either cumulative water injection

or producing water cut. Uniform and homogeneous reservoirs are almost always assumed.

Injection wells in many water injection projects fit no classical pattern. Some of these irregular patterns are

peripheral, crestal line drive, and down dip injection into an aquifer. Accurate predictions of areal sweep

efficiency for irregular patterns can only be made with computer reservoir simulators.

3.6.2 Gas and Water Injection

Like waterflooding, gas and water injection is also used for pressure maintenance and improved

displacement efficiency. Unlike waterflooding, the fluid is injected into the gas cap or aquifer and not into

the producing zone as shown in Figure 26. In addition, gas can be injected to (1) displace unrecoverable oil

that is trapped upstructure of the highest penetration available in a strong waterdrive reservoir, and (2)

prevent oil from migrating into an original gas cap.

One important aspect of gas injection which must always be carefully considered is that the gas has value.

Injection of a saleable commodity must discount to future income. In the case of gas injection for

upstructure drainage, the commodity is unrecoverable.

Generally, the displacement efficiency of gas injection is less than that of water injection. This is because

of the high relative permeability to gas and low gas viscosity. However, where gravity effects are important,

gas displacement may be more efficient than water due to the benefits of gravity drainage. In thick, highly

permeable, dipping reservoirs, typical of salt dome fields, gas displacement efficiency is very high.

3.7 Tertiary Recovery

Tertiary recovery methods are processes designed to recover additional oil that cannot be recovered

profitably by primary and secondary methods. Because of the increasing costs of finding and drilling for new

oil, there now exists economic incentive to recover a portion of the vast reserves left behind in existing

reservoirs.

Several tertiary recovery methods, summarized in Figure 27, have been used but no universally applicable

technique has been found. The objective of several of the methods is to decrease oil viscosity to increase

will productivity or to increase the displacement efficiently of waterflooding. The most promising tertiary

processes are usually grouped into three categories:

3.7.1 Miscible Methods

Refers to processes where the injected gas or fluid is soluble with the residual oil. The methods include


Updated Dec. 1999

high pressure gas, enriched gas, and gas-driven LPG banks. The miscible methods solve the common

problem of limited recovery by gas drive. They introduce a buffer zone of solvent between the gas and the oil

and sweep clean the rock invaded by solvent.

3.7.2 Thermal Methods

Refers to a process in which heat is applied to the reservoir. The methods include underground burning, hot-

water flooding, steam flooding, and stimulation by steam.

3.7.3 Improved Waterflood Methods

Refers to techniques which involve both water additives to improve recovery efficiency and those involving

banks of solvents driven by water. These methods include the use of surfactants, viscous water, CO2, and

alkaline water. Surfactant and alkaline water injection can mobilize the residual oil remaining in the reservoir

after a conventional waterflood and build a “secondary” oil bank.


Updated Dec. 1999

DRILLING SYSTEMS

TABLE OF CONTENTS

1.0 CATEGORIZATION OF DRILLING ......................................................................................... 1

1.1 Location of Hole ............................................................................................ 1

1.2 Type of Hole.................................................................................................. 1

2.0 ROTARY DRILLING OPERATIONS ........................................................................................ 2

2.1 Drilling Overview ............................................................................................ 2

2.1.1 Drill Bits ................................................................................................. 2

2.1.2 Drill Collars ............................................................................................. 2

2.1.3 Drill Pipe................................................................................................. 3

2.1.4 Rotary System........................................................................................ 3

2.1.5 Hoist System.......................................................................................... 4

2.1.6 Derrick ................................................................................................... 5

2.1.7 Fluid Circulation System .......................................................................... 5

2.1.8 Power System ........................................................................................ 6

2.2 Drilling Fluids ................................................................................................ 6

2.2.1 Fluid Bases ............................................................................................ 7

2.2.2 Fluid Additives......................................................................................... 7

3.0 DRILLING PLAN................................................................................................................... 8

3.1 Drilling Program............................................................................................. 8

3.2 Pressure Control ........................................................................................... 8

3.2.1 Overburden Pressure ............................................................................... 8

3.2.2 Fracture Pressure.................................................................................... 8

3.2.3 Formation Pressure ................................................................................. 9

3.3 Casing Program ............................................................................................ 9

3.4 Blow Out Preventers (BOPs) ......................................................................... 10

3.4.1 Types of BOPs....................................................................................... 10

3.4.2 BOP Controls......................................................................................... 11

3.4.3 Kill and Choke System ........................................................................... 12


Updated Dec. 1999

TABLE OF CONTENTS (Cont'd)

4.0 OFFSHORE DRILLING......................................................................................................... 13

4.1 Mobile Offshore Drilling Units......................................................................... 13

4.1.1 Submersible Drilling Rigs ........................................................................ 13

4.1.2 Jack-up Units......................................................................................... 13

4.1.3 Semisubmersible Drilling Rigs ................................................................. 14

4.1.4 Drillships ............................................................................................... 14

4.2 Marine Equipment ........................................................................................ 15

4.2.1 Marine Risers......................................................................................... 15

4.2.2 Guideness Systems ............................................................................... 17

4.2.3 Motion Compensation Systems ............................................................... 18


Updated Dec. 1999

LIST OF FIGURES

FIGURE 1. Drilling System

FIGURE 2. Roller Jet Bit

FIGURE 3. Derrick Pipe Handling System

FIGURE 4. The Mud System

FIGURE 5. Abnormally Pressured Formation

FIGURE 6. Typical Pressure Profile

FIGURE 7. Bottom Hole Pressure

FIGURE 8. Casing Program

FIGURE 9. Subsea Blowout Preventer Stack

FIGURE 10. BOP Stack

FIGURE 11. Annular Blowout Preventer

FIGURE 12. Typical Choke Manifold Assembly

FIGURE 13. Jack-Up BOP Arrangement

FIGURE 14. Floating Drilling System

FIGURE 15. Marine Riser System

FIGURE 16. Riser System Components

FIGURE 17. Typical Moonpool Arrangement

FIGURE 18. Lower Marine Riser System

FIGURE 19. Telescoping Joint

FIGURE 20. Typical Diverter System Subsea

Installation

FIGURE 21. Riser Joint with Air Can

FIGURE 22. Drilling 36” Hole

FIGURE 23. Running 30” Housing

FIGURE 24. Drilling 26” Hole

FIGURE 25. Running 20” Casing

FIGURE 26. Guidelineless Drilling TGB

FIGURE 27. Guidelineless Installation of 30”

Conductor with PGB

FIGURE 28. Jetting of 30” Conductor

FIGURE 29. Running 20” Casing Guidelineless

FIGURE 30. Motion Compensator System

FIGURE 31. Guideline Tensioner System

FIGURE 32. Riser Tensioner Reeving

FIGURE 33. Guideline Tensioner Reeving

FIGURE 34. Crown Block Compensator

FIGURE 35. Drill String Compensators - Tension

Type


Updated Dec. 1999

1.0 CATEGORIZATION OF DRILLING

1.1 Location of Hole

The common objective of any drilling operation is to make a hole. The hole can be located onshore or

offshore; offshore, the hole could be under either a temporary or permanent stationary platform, or the hole

could be under either a temporary or permanent floating platform. The basic systems and methods remain

the same regardless of the location of the hole. Throughout this section the variations will be pointed out in

methods and systems used on land and offshore.

1.2 Type of Hole

The objective in making a hole is to turn it into a well. The well can be for exploration or development;

sometimes an exploratory well is later turned into a development well (e.g., offshore exploratory well

converted to subsea completion for tie-back to permanent facilities).

The only way to locate and evaluate hydrocarbon reserves is to drill an exploratory well. The initial

exploratory well in a field is called a wild cat. Once the reservoir is located, delineation wells are drilled at

the perceived lateral boundaries of the reservoir to confirm its size and producing characteristics.

In order to produce the discovered reserves, development wells must be drilled into the reservoir. The

reservoir engineer dictates the location of these wells after studying the results of the exploratory drilling

program. Development wells can be used to produce hydrocarbons, or used to inject water or gas in order

to maintain pressure in the producing reservoir.

Exploratory wells are drilled with systems leased for the gathering of information; offshore, temporary

platforms are used to support the drilling systems (i.e., mobile drilling units). Development wells are drilled

with either leased or purchased systems, but the platform supporting the drilling system is usually

purchased. Regardless of the intended use of the well, the methods and systems used in drilling the hole

do not vary.


Updated Dec. 1999

2.0 ROTARY DRILLING OPERATIONS

2.1 Drilling Overview

The vast majority of holes are drilled with rotary drilling methods, including holes drilled with a high angle of

deviation form the vertical over most of the hole depth (i.e., deviated wells). Holes are being drilled

horizontally or near horizontally using specialized systems for such operations as power transmission (i.e.,

downhole motors), directional control (i.e., gravity is no longer controlling) and cementing. This section only

introduces the systems and methods associated with rotary drilling. Figure 1 shows the basic components

of conventional rotary drilling done on land or offshore that are referred to in the following sections.

2.1.1 Drill Bits

Though the product of the entire drilling operation is a hole, only the drill bit actually makes the hole. The

roller cone rock bit is the most commonly used drill bit. Each cone is equipped with teeth that chip the

formation as the bit is rotated. The chips, or cuttings, are removed from the teeth and the bottom of the hole

by the action of the circulating drilling fluid. The design of the majority of roller bits is to have teeth of varying

length and spacing on the three cones, the spacing and length of the teeth depending upon the formation to

be drilled. Long, widely spaced steel teeth are used in soft formations; harder formations use shorter teeth

made from harder materials such as tungsten carbide insets laid into the cutting faces of the cones.

A widely used variant of the standard roller bit is the jet bit in which the drilling fluid exits jet nozzles forming

high velocity streams direct at the bottom of the hole. These jets of fluid better lift the cuttings off the face of

the hole, allowing the drill teeth to strike new formation rather regrinding loosened cuttings. Figure 2 is a

visualization of the downhole action of a roller jet bit. The pressure losses through these jetting nozzles are

considerable and require both extra pump capacity and pump horsepower.

Poly-crystalline diamond (PDC) bits have become widely used in the last 10 years. These bits incorporate

synthetic poly-crystalline diamond and/or tungsten carbide cutters into a steel bit body. The bits cut with a

shearing action rather than the chipping action of the roller cone bit, and are used in moderate to soft

formations with less weight on the bit and good penetration rates.

Diamond bits are most widely used as core heads. A core head is a bit with a cut out in the center which

allows a core or spine of rock to left when the hole is cut. The core is recovered by a core barrel.

The upper connection of the rock bit is normally a tapered right hand tool joint pin. This tapered thread

makes up into a drill collar sub which is usually a short, heavy-walled section of drill collar with each end

threaded with a tool joint box.


Updated Dec. 1999

2.1.2 Drill Collars

The next section of the drill string above the bit and drill collar sub is comprised of drill collars. Drill collars

are lengths of heavy weight steel pipe threaded with a right hand tool joint box up and pin down, which is the

conventional way for oilfield tubulars to be connected. The drill collars come in varying lengths and sizes.

Most commonly they are 30 ft. long.

The purpose of the drill collars is to provide the weight which will act on the bit as it is rotating in order to

improve the penetration rate. The bit weight required will dictate how many drill collars are included in the

drill string. A certain length of drill collars above the bit is under compressive loads while drilling is in

progress. This explains why the drill collars are very rugged components of the drill string and why the

threaded connections are so strong. The drill pipe and the balance of the drill collars are in tension during

the drilling operation. Normal practice is to keep the ‘neutral point’, the transition point between

compression and tension, in the drill collar section the drill string. The neutral point appears to be a

common place for failure of the drill collar tool joints.

2.1.3 Drill Pipe

Above the drill collars will be the drill pipe section of the drill string. Drill pipe is lighter weight steel pipe

threaded with a right hand tool joint box up and pin down. The drill pipe comes in varying lengths and sizes.

Typically, the drill pipe would be in 31’ lengths, 5” OD equipped with 4 ½” API internal flush tool joint

threads, box up and pin down. In normal drilling operations the drill pipe is under tension as the drill string is

being rotated to the right.

2.1.4 Rotary System

At the top of the drill string is a kelly saver sub and the kelly. The kelly saver sub is a short section of

heavy-walled pipe with drill pipe tool joint connections, box up, pin down. The purpose of the kelly saver sub

is essentially to protect the lower threaded connection of the kelly. The saver sub remains permanently

connected to the lower end of the kelly until the thread on the lower end of the saver sub needs replacement

or repair. The kelly is constructed from high grade steel pipe with either a square or hexagonal outside

profile. On land drilling rigs the kelly is normally about 40’ long. However, on floating drilling vessels the

kelly will normally be about 54’ long; the extra length being required to accommodate the up and down

motion of the drilling vessel.

The kelly is the component of the drill string to which the right hand rotation is applied. This in turn rotates

the drill string and drill bit to the right. The right hand rotation is applied to the kelly by way of the kelly

bushing. The kelly bushing has a square or hexagonal hole through it which corresponds to the outside

profile of the kelly. The kelly bushing in turn sits and locates in the rotary table and receives its right hand

rotation when the rotary table is rotated.


Updated Dec. 1999

The rotary table sits on very large steel beams, called ‘rotary beams’, at the rig floor level. It is centered in

the middle of the rig. The main function of the rotary table is to apply rotation and transmit torque into the

drill string by way of the kelly bushings and kelly. The center section of the rotary table is the part that

rotates and this center section typically has a 37 ½ in. opening without the master bushings in place. The

master bushings are split and sit into recesses in the center section of the rotary table. The master

bushings have a tapered conical hole into which drill pipe slips can be set when it is necessary to support

the drill string weight, as would be the case when another joint of drill pipe is added or when tripping the drill

pipe in and out of the hole. As the kelly is rotated during drilling operations, it moves up and down by

means of rollers in the kelly bushing. In offshore drilling operations however, it is necessary to lock the kelly

bushings in the rotary table. This is because the friction bind between the kelly and the bushing (as the

vessel moves up and down) is sometimes sufficient to lift the kelly bushing drive pins out of the matching

recesses on the rotary table. When the kelly is picked up sufficiently to clear the rotary table, as is the

case when adding another length of drill pipe, it will also pick up the kelly bushings out of the rotary table.

The kelly and kelly bushings are then handled together. The upper end of the kelly is equipped with a left

hand thread, as the right hand rotation of the drill string tends to disconnect right hand threads above the

rotary table.

The swivel is the next component of the drilling system and it is connected to the kelly by way of the left

hand thread at the top of the kelly. The swivel supports the total weight of the drill string and allows it to

rotate on a large bearing contained within the swivel body which does not rotate. The swivel also has the

inlet on it through which the circulating drilling fluid is pumped into the bore of the kelly and the drill string.

The swivel body has a large heavy bail at the upper end which is engaged by the drilling hook of the traveling

block.

An alternative to the Kelly and rotary table is a top drive system. Top drive systems transmit the torque

directly to the top of the drill string. The top drive systems are a packaged unit consisting of hydraulic or

electric motors driving a reduction gear which is directly connected to the lower end of the swivel. The

advantages of the power swivel is that it allows new sections of drill pipe to be installed in the drill string

more quickly than the Kelly and rotary table systems, and also allows the operator to simultaneously trip

the pipe and circulate during trips.

Top drive systems are being retrofitted on many existing rigs as they are now proven to improve drilling

speeds and provide more flexibility in the drilling operations. Rotary and Kelly systems are still retained for

back-up to the top drive systems.

2.1.5 Hoist System

The traveling block and hook are part of the hoisting or lowering mechanism by which the drill string is pulled

out of, or lowered into, the hole. Figure 3 shows the typical arrangement while tripping the drilling pipe. The


Updated Dec. 1999

traveling block usually houses 6 large sheaves, or pulley wheels, and the drilling hook is normally integrated

into the traveling block housing. The travel block is strung up to the stationary crown block at the top of the

drilling derrick or mast. The traveling block, drilling line and crown block are in essence a giant block and

tackle.

The crown block also has 6 large sheaves and the drilling line can be strung over 4, 5, or 6 of the sheaves.

This gives rise to the terminology; ‘8-line stringing’ (4 sheaves), ‘10-line stringing’ (5 sheaves), and ‘12-line

stringing’ (6 sheaves). The number of drilling lines strung is selected according to the drill string loads are

being supported, and the desirability of hoisting and lowering the drill string in and out of the hole at

acceptable speeds. As in any block and tackle system, one end of the drilling line is anchored at the foot of

the drilling derrick or mast by way of a ‘dead line’ clamp. The moving end of the drilling line, the ‘fast line’, is

wound onto the drum of the hoist or drawworks on the rig floor.

In offshore drilling operations the floating drilling vessels are subjected to different motions due to wave

action, notably heave, pitch, roll, yaw, etc. These movements are transferred into the traveling block and

could cause the block to move about. However, a rigid tracking system is installed in the mast or derrick

which stabilizes the traveling block in order to prevent any swinging action of the block.

The hoisting unit which winches the drilling line in, and lets it out, in order to raise or lower the traveling

block and hook load, is called the drawworks. Because of the high loads carried on the hook, the

drawworks is equipped with a very powerful brake system. Most rigs are equipped with a dual braking

system, one mechanical and the other hydraulic or electric. Inside the drawworks is a system of gears,

which permits the selection of different operating speeds. The gear selection will depend on the load of the

pipe being pulled from the hole.

2.1.6 Derrick

The structure that supports the crown block and all the weight suspended on the drilling lines below is called

the derrick or mast, and offshore is typically rated at 1,100,000 lbs. load capacity. Most derricks (or

‘Standard derricks’ as they are known) are open steel structures made with four supporting legs from the

corners of a more or less square base.

Masts are more slender and tend to occupy less base area. Masts are usually cantilevered, and can be

lowered to a horizontal position during rig movements, whereas the Standard derrick is usually erected at a

drilling site and dismantled at the end of the hole.

Masts and derricks are supplied in various heights and can range from 60’ to 187’ in height. The most

popular height is about 147’ to accommodate motion compensators and power swivels in the drilling

system. Within the structure of the mast or derrick is provision to stand and rack the drill string as it is

pulled out of the hole. Normally the drill pipe is ‘stood back’ in stands of three interconnected joints called


Updated Dec. 1999

‘thribbles’, which have an approximate length of 90 ft. The masts and derricks also have to withstand side

loads caused by high winds, and most offshore masts and derricks have wind resistance capabilities in the

region of 100 - 165 mph.

2.1.7 Fluid Circulation System

One of the essential support systems for rotary drilling is the circulating system. Figure 4 illustrates the

key features of the system. High pressure drilling fluid from the mud pump (A) is conducted into the

standpipe usually attached to a derrick or mast leg, and then into the flexible rotary hose. The rotary hose

is connected to the inlet of the swivel (B) through which the drilling fluid then enters the kelly (C) and drill

string (D). The drilling fluid is pumped down inside the drill string, through the drill bit (E) and back up the

annulus (F) between the drill string and the wellbore. The returning drilling fluid, with its entrained formation

cuttings, passes over a vibrating screen called a ‘shale shaker’ (G). The shale shaker removes the cuttings

from the drilling fluid and the drilling fluid drops into a settling pit (H). The action of the settling pit allows

finer formation particles to drop to the bottom of the pit as the drilling fluid moves through this settling pit to

the suction pit. The suction line of the mud pump or pumps takes the treated drilling fluid from this suction

pit and the circulation cycle starts again.

The pump used to circulate the drilling fluid is called the mud pump, or slush pump. Typically these pumps

are large positive displacement duplex or triplex pumps, and depending on the liner sizes, piston stroke, and

strokes per minute, can have capacities up to 900 gallons per minute and output pressures up to 5600 psi.

The rotary hose is very important and is exposed to extremely rugged service conditions. It has to be

flexible in order to accommodate the mechanical action of raising and lowering the drill string with the

drawworks. On floating drilling vessels equipped with motion compensators the rotary hose also has to

accommodate the up and down motion of the vessel. The rotary hose has to withstand both high pressures

and the highly erosive action of the drilling fluid. Rotary hoses are usually rated at 5000 psi working

pressure. Usually the rotary hose is 75 ft. long and 3 ½ in. ID.

After the drilling fluid has passed through the bit, it returns to the surface up the annulus between the drill

string and wellbore. On a land drilling operation the ‘returns’ pass through the BOP stack installed on the

wellhead and finally exit through the mud return flowline in the bell nipple installed on top of the BOP stack.

In offshore drilling operations the drilling fluid ‘returns’ have to travel further and pass through the marine riser

system (Section 3.3.1), attached to the subsea BOP stack before they finally exit through the mud return

flowline in the bell nipple attached to the inner barrel of the telescopic joint.

2.1.8 Power System

Offshore drilling systems generally use diesel-electric generator sets to produce all alternating current (AC)

power for the rig and the support equipment. The drawworks, mudpumps, rotary, and other systems which


Updated Dec. 1999

require high power and variable speeds generally use direct current (DC) electric motors with the DC power

being derived from the AC electrical system through silicon controlled rectifiers (SCRs).

2.2 Drilling Fluids

The drilling fluids that have been referred to in the preceding sections can be varied in many ways, in order

to suit the formations and the anticipated pressures that the wellbore will pass through. Some of the

important functions of the drilling fluid are:

To clean the bottom of the hole so that the bit can drill.

Remove the cuttings generated by the bit action and transport them to the surface.

Provide cooling and lubrication for the bit and drill string during drilling operations.

Control formation pressures by exerting an overpressure on the formation. This is achieved by controlling

the hydrostatic head of the drilling fluid in the hole.

Prevent the wall of the open wellbore from caving or collapsing into the wellbore.

2.2.1 Fluid Bases

Most drilling fluids are water based. Oil based systems are used in deep wells where downhole

temperatures are above the boiling point of water; mineral oil based systems are used when cuttings must

be disposed of in environmentally sensitive areas.

In many areas water is the drilling fluid for the shallow sections of the hole being drilled. However, although

water is excellent in terms of penetration rates, it does not have all the properties to provide the formation

and pressure control mentioned above.

2.2.2 Fluid Additives

When drilling and circulating water as the drilling fluid, the water picks up a good deal of naturally occurring

clay minerals, and in fact, starts to form a natural mud, which is how the term originated. The mud formed

is thin and slurry. This natural mud slurry has improved properties over plain water, in that it has a higher

viscosity which improves its cutting load carrying capacity, and it has an increased density which means

that the hydrostatic head of the drilling fluid in the wellbore is also increased.

The naturally occurring clays when hydrated in the drilling water tend to be unstable and particularly prone to

contamination; for instance, salt water entering the drilling fluid from one of the formations penetrated by the

wellbore can cause the gel to flocculate and lose its suspending power. This problem has been solved by

using specially prepared bentonitic clays. They form very stable gels and provide a much greater support for

cuttings, and also greater support for the powdered weighting materials.


Updated Dec. 1999

The most common weighting material used is barytes (barium sulphate). It is supplied in finely powdered

form that is introduced into the circulating drilling fluid and remains suspended in the drilling fluid due to the

gel strength of the slurry. The specific gravity of barytes is about 4.2 which means that the density of the

drilling fluid can be increased greatly by addition of the powdered barytes. This in turn provides the control

of the hydrostatic head exerted by the drilling fluid on the formation.

All drilling fluids or muds can be tested in order to determine their physical and chemical properties, and this

is done on a regular basis at the rig, either on land or offshore. The most regular tests performed measure

the viscosity and weight of the drilling fluid or mud. Other tests show the acidity or alkalinity of the mud in

terms of its pH value; the amount of mud cake or filter cake the drilling fluid or mud deposits with a known

pressure differential; the amount of solids in the mud as a volumetric percentage, and the amount of fluid (be

it water or oil), in the mud as a volumetric percentage. These properties provide a guide for the mud

engineer who can then prescribe a treatment for the mud, if required, to improve the muds performance in

the hole.


Updated Dec. 1999

3.0 DRILLING PLAN

3.1 Drilling Program

As drilling is a costly operation, a thorough drilling plan is essential to ensure that the hole can be drilled

safely with the most efficient use of resources. Drilling plans also contain allowances for contingencies

such as downhole, or formation related problems, rig limitations, downtime, and remote possibilities of

blowouts.

The actual plan for removing rock and creating a hole is the drilling program. Though the hole is drilled from

the surface, the drilling program is designed from the target depth up. The planning of a hole starts with the

determination of objectives for both the depth of the target formation and the hole size in that formation. The

drilling program then is the strategy for attaining these objectives with the minimum hole and casing sizes

possible, while allowing for contingencies.

Before discussing the selection of casing sizes and their individual lengths, it is instructive to review the

mechanics of controlling formation pressures.

3.2 Pressure Control

The control of formation pressures while drilling a hole is referred to as pressure control. If the hydrostatic

pressure of the drilling fluid is not adequate, the well fluids can come out of an open hole formation (i.e., a

formation not sealed by casing). This situation is referred to as a ‘kick’.

The hydrostatic pressure of the drilling fluid is a function of the mud weight in the annular column (i.e., the

amount of baryte in the drilling fluid mixture). In deciding on the appropriate mud weight, the driller must

take into account overburden pressure, formation pressure and fracture pressure.

3.2.1 Overburden Pressure

The overburden pressure is the measure of the stress in the formation rock caused by the weight of the

material above it. The density of rock varies with depth but is generally assumed to be about 94 #/ft3. The

rock stress gradient in a formation is generally assumed to be about 1 psi per foot of vertical depth.

3.2.2 Fracture Pressure

The fracture pressure is the pressure of the fluid in the rock pores that will cause the formation rock to

fracture and separate, opening fissures in the formation. This pressure is usually equal to the overburden

pressure plus the tensile strength of the rock.

Open fissures in the rock increases the rock porosity and permeability. This is sometimes a desirable


Updated Dec. 1999

feature when trying to improve the productivity of a producing the formation.

Fracturing a formation is not a desirable occurrence while drilling a hole because it creates a sink for the

drilling fluids to flow into, leading to the loss of the circulation fluid. With sufficient lost circulation fluids,

also called lost returns, the hydrostatic head of the drilling fluid column can decrease to a point where the

formation pressure of a deeper zone can cause a kick.

3.2.3 Formation Pressure

The fluid pressure in the rock pores is the formation pressure. A formation is considered normal if the

formation pressure equals the normal hydrostatic gradient pressure.

Formations are not typically solid rock but rather are porous, containing primarily salty water called brine.

The water pressure in the rock pores increases with depth by the hydrostatic gradient, typically .465 psi per

foot of vertical depth.

A formation is abnormally pressured if the formation pressure is above the hydrostatic gradient pressure due

to the effect of the rock stress gradient. This is generally the case in most regions of the world. Figure 5

illustrates an abnormally pressured formation.

A formation is subnormally pressured when the formation pressure is less than the normal hydrostatic

gradient pressure. This occurs infrequently.

Figure 6 shows the formation, fracture and overburden pressures plotted for a hypothetical hole. The

formation pressure is normal down to 7000 ft where it becomes abnormal.

A drilling engineer does not refer to such composite profiles in order to keep the mud weight between the

formation and fracture pressures. Instead, they generally work with gradients for mud weight and the

resulting pressure profile in the hole, as shown in Figure 7.

3.3 Casing Program

Part of planning the drilling of a hole is to design the casing program. Casing strings are set and cemented

into on open hole for the following reasons:

To provide a structural member to support the wellhead and deeper set casing strings.

To isolate shallow, weaker formations from lower, higher pressured formations.

To isolate troublesome formations from the working area of the hole.

Figure 8 shows an example of a typical casing program. The shallowest casing string, or conductor pipe,

generally serves as a structural member, and keep the less consolidate rock from sloughing off into the

hole. Prior to drilling into the deeper and abnormally pressured formations, a string of surface casing is set

to permit increasing the mud weight. As drilling progresses deeper towards the target formation, additional


Updated Dec. 1999

strings are set to isolate the lower strength zones higher up in the hole.

Most casing programs allow for the use of ‘trouble strings’ which may be set if an unanticipated condition in

the hole requires a zone to be isolated before the target formation can be reached. The need for trouble

strings is more prevalent in exploratory drilling where little is known.

A production casing string is run in development wells in order to isolate the production zone from the rest of

the hole. This string will support the production tubing, with the production zone isolated by packers. In

some cases, the production casing serves as the production conduit.

3.4 Blow Out Preventers (BOPs)

In case of a kick, Blow Out Preventers, or BOPs, are used in order to prevent disastrous results from the

potentially uncontrolled situation. The equipment has been developed over the years until there are now two

basic types of BOP and around the two types of BOPs various combinations have evolved into systems or

stacks. In addition to the systems, or stacks, there are ancillary control devices so that the well can be

flowed or the excess pressure relieved under controlled conditions. These other items are a kill line and a

choke line from the wellhead and a choke manifold. Figure 9 shows a schematic of a typical stack.

There is no basic difference in the BOPs used onshore and on a platform and there is only detail differences,

primarily in the control system, between those used on the surface and those used on the seabed when

drilling from a floating rig. The principles of operation and the internals of the BOPs are the same.

BOPs are identified by their bore and pressure rating. The bore limits the maximum tool size which can be

run through the BOP. Standard BOP pressure rating are 2000, 5000, 10,000, or 15,000 psi. The required

BOP pressure rating is generally determined by the depth of the well being drilled and the anticipated

formation pressures in the area.

Floating drilling units which drill and complete the majority of subsea wells generally use 18-3/4” - 10,000 psi

working pressure BOP systems. In the past 10 years the higher pressure 18-3/4” - 15,000 psi systems

have become available and rigs equipped with these units are in demand for high pressure/high temperature

(HPHT) wells and for deepwater drilling operations.

3.4.1 Types of BOPs

There are two types of BOPs: Annular, and Ram. Figure 10 shows a cut away of a typical subsea stack

with both types of BOPs. The annular consists of a ring of rubber with metal inserts which, when activated,

is forced inward towards the center of the wellbore closing around whatever is in the well. The ram type have

two separate blocks of metal, with rubber seals which, when activated, meet in the center of the wellhead

closing around the pipe that is in the hole or sealing if there is nothing in the hole.


Updated Dec. 1999

In an annular preventer, as pictured in Figure 11, the actuating cylinder is around the outside of the wellbore

and the inside of the cylinder has a tapered side, against which rests the outside of the BOP rubber, which

has a taper the reverse of the cylinder. On being actuated, the cylinder moves upward (the oil above the

cylinder being returned to an oil reservoir) forcing the rubber (with metal inserts) inward to close around

whatever is in the hole, be it drill pipe, tool joint, kelly or nothing.

In the ram type preventers there are two types of rams: Pipe Rams and Blind Rams. The pipe rams will

only fit one specific size of pipe as the rams have to be cut out so as to fit around the pipe size in question;

therefore, for every size of pipe used, there is a different size ram.

To close on an empty hole, blind rams are used. These have no cut-outs and are made so that they will

mesh into each other when closed, sealing the hole completely. A variant of this type is the shear ram,

which has the same function as the blind ram but also includes a scissor action cutting shear which will cut

through any pipe that is in the hole.

The number of BOPs that are used on any hole will vary with the type of hole being drilled. Onshore the

number will be three or four, consisting of one annular preventer, one pipe ram and one blind ram. If a fourth

preventer is added, it will also be a pipe ram. The same configuration will apply on a platform or on a jack-

up rig. On a floating rig with a seabed system, there will be five or six BOPs, consisting of one or two

annular preventers, three pipe ram preventers and one blind/shear ram.

All BOPs are worked in the same manner, by hydraulic pressure. When it is desired to shut the BOP, a

valve is operated either by the driller or at a remote position, and allows hydraulic pressure to enter the BOP

closing it. For opening, pressure is applied to the opposite side of the operating mechanism and the BOP is

opened.

The ram type BOPs have cylinders on both sides fixed to the ram carrier. To close the ram, hydraulic fluid

is admitted to the outside of the piston in the cylinders on either side closing the ram. Opening is the

reverse, with the fluid being admitted to the center of the cylinders. Changing the rams is in all cases a

relatively simple matter though the method does vary.

3.4.2 BOP Controls

The control panels for the BOPs will be by the drillers position and there will be remote panels away from

the rig so that the BOPs can be closed even if the rig has had to be evacuated (this is of great use if H2S is

present). The hydraulic fluid for actuating a BOP system is kept in accumulators, which are pressure

vessels with nitrogen and hydraulic fluid. The hydraulic fluid is pumped into the accumulator until the

required pressure is reached when the pump automatically shuts down. On opening the valve to actuate the

BOP, the nitrogen expands forcing the fluid into the BOP and the surplus fluid on the other side of the

operating mechanism in the BOP is returned to the fluid reservoir in the accumulator system.


Updated Dec. 1999

3.4.3 Kill and Choke System

Once the kick has been controlled by the use of BOPs, other equipment is required to control the annulus

pressure while circulating the kick out of the hole. This equipment includes kill and choke lines, and a

choke manifold. A heavy drilling fluid, called a kill fluid, is pumped into the annulus to regain hydrostatic

pressure control over the formation fluids. The fluids already in the annulus are vented through the choke

line.

The annular fluids are vented to the choke manifold, which consists of a remote control choke that is

controlled from the drillers position, a hand operated adjustable choke, and fixed chokes. Figure 12 is a

schematic of a typical manifold for a subsea BOP. By adjusting these chokes it is possible to control the

back pressure in the annulus. The remote control adjustable choke enables the driller to be able to hold the

desired pressures on the annulus while being able to control pumping rate, etc. With the hand operated

choke it is necessary to have an operator at the choke manifold and communication is a possible problem.

Fixed chokes can be used if the rate at which the fluid is coming out of the well is too great for the

adjustable choke and then the fixed choke is used in parallel with the adjustable choke.


Updated Dec. 1999

4.0 OFFSHORE DRILLING

4.1 Mobile Offshore Drilling Units

The original units were simply land rigs taken into shallow waters and placed on a structure for drilling. The

same drilling techniques that had been developed on land were used on the first offshore rigs. The need to

drill in deeper waters created a new breed of drilling rigs. There are four basic types of offshore mobile

drilling units: the submersible, the jack-up, the semisubmersible, and the drillship.

4.1.1 Submersible Drilling Rigs

The submersible drilling unit is sometimes called the swamp barge or posted barge. This type of unit is

used in shallow waters such as rivers and bays, usually in waters up to 50 feet deep. The semisubmersible

is floated to location like a conventional barge and is then ballasted to rest on the river bottom. The lower

hulls are designed to withstand the weight of the total unit and the drilling load. The semisubmersible has

two hulls. The upper hull, sometimes referred to as the “Texas” deck, is used to house the crew quarters

and equipment, and the drilling is performed through a slot on the stern with a cantilevered structure. The

lower hull is the ballast area and is also the foundation used while drilling.

4.1.2 Jack-up Units

Jack-up designs can generally be classified into two basic categories: independent leg jack-ups and mat

supported jack-ups. Each unit has its particular value.

The independent leg jack-up depicted in Figure 13, will operate anywhere currently available, but it is

normally used in areas of firm soil, coral, or uneven sea bed. The independent leg unit depends on a

platform (spud can) at the base of each leg for support. These spud cans are either circular, square, or

polygonal, and are usually small. Spud cans are subjected to bearing pressures of around 5,000 to 6,000

pounds per square foot, although in the North Sea this can be as much as 10,000 psf. Allowable bearing

pressures must be known before a jack-up can be put on location.

The mat supported jack-up is designed for areas of low soil shear value where bearing pressures must be

kept low. The mat is connected to all the legs. With such a large are in contact with soil, bearing

pressures of 500 to 600 psf usually exist. The mat type jack-up penetrates the sea bed perhaps 5 or 6 feet.

This compares with a penetration of perhaps 40 feet on an independent leg jack-up. As a result, the mat

type unit requires less leg than the independent jack-up for the same water depth. The mat type unit

requires a fairly level sea bed. A maximum sea bed slope of 1 ½° is considered to be the limit. Mats are

designed for uniform bearing. In areas where there is coral or large rock formations, the uneven bottom

would probably cause a structural failure.


Updated Dec. 1999

Jack-ups can be either self-propelled, propulsion assisted, or nonpropelled. The majority of jack-up rigs are

nonpropelled. The self-propelled unit requires a specially trained crew of seamen as well as a drilling team.

Jack-ups have been built with as many as 14 legs and as few as 3 legs. As the water depth increases and

the environmental criteria become more severe, more than 4 legs is impractical. The prime forces on a jack-

up are generated from the waves and currents, hence, the less exposure to the waves and currents the

fewer the forces being developed on the unit.

The early jack-ups were designed to operate in the U.S. Gulf of Mexico in water depths up to 200 feet.

Wave heights in the range of 20 to 30 feet with winds up to 75 mph were considered as design criteria for

these units.

Newer units have been designed to operate in 360 ft water depth in the North Sea with design criteria of 90

foot wave, 125 mph wind and 2 to 2 ½ knot currents.

4.1.3 Semisubmersible Drilling Rigs

The semisubmersible evolved from the semisubmersible. The general configuration of a semisubmersible

consists of two longitudinal lower hulls which are used as ballast compartments to achieve the necessary

drilling draft. The semisubmersible is ballasted to float on these hulls during transit. This last unit does not

offer the towing capabilities of twin hull units, but it does provide good drilling characteristics.

Semisubmersibles are held on location either by a conventional mooring system or by dynamic positioning.

The conventional mooring system usually consists of 8 anchors placed in a spread pattern and connected

to the hull by chain or wire rope, sometimes even a combination of both. The dynamic positioning method is

an evolution of the ship sonar system whereby a signal is sent out from the floating vessel to transducers

set out on the ocean floor. Dynamic positioning becomes a greater necessity as the water depth increases.

The motion that causes problems for any floating drilling vessel such as a semisubmersible is heave (i.e.,

vertical motion). Heave is generated in response to exposed waterplane area. The lower submerged hulls

supply the primary displacement. The columns connecting the hulls to the topside deck have a small

waterplane.

With the loss of waterplane area to reduce heave response, a reduction in stability follows. A compromise

between acceptable heave response and adequate stability is needed.

Some semisubmersibles are self propelled. Propulsion is a large initial expense which can be recovered in

a reasonable period of time if mobility is required. Considering that once a unit has reached location it is

generally in that area for a long time, propulsion units become not only unnecessary but they also use up

valuable consumables (weight) capacity.


Updated Dec. 1999

4.1.4 Drillships

The drillship is a shipshape vessel used for drilling purposes. Earlier drillships were converted vessels,

either barges, ore carriers, tankers, or supply vessels.

Drillships are the most mobile of all drilling units, but are also the least productive. The configuration that

permits mobility results in bad drilling capabilities. The drillship, because of its surface contact with the

sea, develops very large heave response compared to the semisubmersible. It is possible, by means of

stabilizing tanks and other methods, to reduce roll on drillships, but heave cannot be reduced. A

subsequent increase in “rig downtime” or “lost” time occurs. This increases the demand for the use of

compensation devices.

Mooring for drillships is very similar to the methods previously discussed for semisubmersibles. There is

one additional system that has been developed on a drillship - the “Turret” system. This is a spread mooring

tied to a turret at the mid section of the vessel. The moonpool is in turret. The rest of the vessel can rotate,

or weathervane, around the fixed mooring.

4.2 Marine Equipment

A special suite of equipment, illustrated in Figure 14, is used offshore in drilling in order to accommodate the

water column and the relative motion between the rotary table and the seabed on floating drilling units. The

marine drilling riser and guideness systems (guideline and guidelineless) accommodates the water column.

Motion compensation systems for the riser, guidelines and drill pipe accommodate the relative motion.

4.2.1 Marine Risers

A riser can be simply described as a conduit from the platform to the ocean floor which transmits the drilling

mud and serves as a guide for the drill string. There are two broad classes of risers, those used for mobile

drilling operations and those used for production operations.

In mobile drilling, the riser tube running from the vessel down to the wellhead is normally called a riser while

the first casing joint running from the wellhead slightly above the mudline down through the template to 30-

100 ft below the mudline is called a conductor or surface pipe. In production operations, the riser tube

running from the platform deck down to the wellhead is also sometimes called a conductor.

In mobile drilling operations conducted with a jack-up rig (See Figure 13), the riser runs from the drilling deck

down to the wellhead. The drilling fluid is pumped down the drill string. The mud returns in the annulus

between the string and the riser in the water or between the string and the casing for that part of the drill

string below the subsea wellhead. Ordinarily, when oil is struck in mobile drilling the well is tested and

capped and the rig moves on to another drilling site. In most areas the regulations require that all equipment

be removed from the ocean floor. The riser string can then be reused.


Updated Dec. 1999

Figure 15 shows a perspective view of a marine riser system for a semisubmersible rig. Figure 16 illustrates

the arrangement of the riser system. It is important to note that the riser is not a simple piece of equipment

but rather a complex system of component parts. The riser string for a floating exploratory vessel is usually

made up of 50 ft long joints which can be stacked and stored on deck during transit from one drilling location

to another. The ends of each joint have quick-disconnect couplings permanently attached to the joint. The

telescoping joint which is at the upper end of the riser string is usually designed for a maximum heave of

between 15 and 30 ft.

Figure 17 shows the general arrangement on a floating drilling rig. A constant force tensioner system is

attached to the top of the fixed outer barrel of the telescoping joint to provide enough axial force in the riser

string to prevent buckling. The outer barrel and the riser string have lateral movement with vessel surge and

sway but essentially no vertical movement with vessel heave. The vessel and the inner barrel of the

telescoping joint move together vertically with vessel heave. The optimum tension is a function of water

depth and operating conditions.

Ball joints on each end of the riser allow for rotation in any direction up to about 7-10 degrees. Actually,

only a few operators insist on two ball joints, which offer more reliability than a single ball joint, because the

use of two ball joints incurs greater costs and greater running time. The usual arrangement for floating

drilling operations is a gimbal under the drilling deck and one ball joint attached to the top of the subsea

BOP stack, which sits on the wellhead. The wellhead attaches to the base template that is set with the

conductor type at the beginning of the operation.

The first riser systems had the choke and kill lines strapped to the riser pipe. Most riser systems now use

integral choke and kill lines which are permanently attached to opposite sides of the riser and have their own

connectors. When the riser joints are stabbed and quick-connected the receptacles allow the choke and kill

lines to be stabbed and automatically connected at the same time.

The choke and kill lines run from the deck along the riser string down to the wellhead. At the lower riser ball

joint there are various schemes, such as looped pipes, to get the required flexibility in a jump line

arrangement running from the bottom of the riser string (top of ball joint) around the ball joint to the BOP

stack. The choke and kill lines control kicks in order to prevent them from developing into blowouts.

Figure 18 shows the general arrangement at the wellhead. When a potential blowout is detected, mud is

pumped down the kill line at the BOP stack to restore pressure balance in the hole. When excess gases

occur the annular and ram type BOPs are closed around the drill string. The gas is relieved at the choke

manifold on the BOP stack by running up the choke line on the riser string. As the gas expands it proceeds

up the choke, displacing more mud and traveling faster as the gas bubble or gas-entrapped mud approaches

the mean water line. Without the choke, the gas would push out the annulus mud between the drill string

and the riser control from the weighted mud would be lost.


Updated Dec. 1999

There are two basic types of telescoping joints used with marine risers. The constant tension system

(remote axial tensioning system) is most often used because maintenance is easier. This method uses a

linkage system at the base of the drilling floor to maintain equal force on the several wire ropes attached to

the outer barrel of the telescoping joint. Figure 19 illustrates a general arrangement.

An alternate design of telescoping joint uses the direct axial tensioning method. This is a procedure where

the seals and guide rings on the telescoping joint are designed to compensate for internal pressure so that

the telescoping joint has the dual function of allowing vessel heave and acting as a direct tensioning piston.

A diverter is located at the top of the telescoping joint, as shown in Figure 20. Depending upon the

magnitude of the kick, the gasified mud is valved either onto the shale shakers or to port.

Most floating exploratory vessels are now outfitted with a riser system for a maximum water depth of about

1,200 ft. Several floating rigs in operation will have riser systems for the extreme water depth of 3,000 ft.

One drillship has a riser system for 7,500 ft, and semisubmersibles have been built to accommodate 10,000

ft water depth.

A drawback with risers for over 6,000 ft water depths is that the static head of heavy drilling fluid (e.g. 20 lb.

mud) could be about 7,500 psi at the mudline and proportionately greater with drilling depth compared to the

normal water pressure of about 3,000 psi at the mudline. This extraordinarily high pressure can cause

severe fracturing of the formation. Very light drilling fluids are used to avoid fracturing the shallow

formations, necessitating additional casing strings as the drilling goes deeper.

The maximum tension in the riser occurs at the top of the riser string and decreases with water depth. In

very deep water, some type of added buoyancy is required to stay within the practical limits of the tensioner

system. Figure 21 shows a riser joint equipped with a air can system. However, it must be remembered

that the current drag force goes up as the square of the velocity and increases with riser diameter. This

means that the outside diameter of the added buoyancy cylinders should be minimized. The optimum

design riser has the smallest diameter and lowest possible wall thickness consistent with allowable stress

levels and allowances for wear and/or abuse.

4.2.2 Guideness Systems

There are two means to guide objects from the drilling floor to the seafloor. The most common system is

guidelines, either 2 or 4, run between a base template and the moonpool. The second system, used in very

deep water, is guidelineless. This system incorporates a baseline system of acoustic transponders to

determine the relative positions of the object being lowered, and the seafloor target, usually the well location.

The guideline system is established by running a temporary guide base to the seafloor on a running, as

shown in Figure 22. This guide base provides to guidelines which are used to guide the drillstring for

creating the hole for the 30-inch surface casing. The 30-inch case is run with the permanent guide base as


Updated Dec. 1999

shown in Figure 23. Sometimes the 30-inch casing is jetted, or washed, into the seafloor by pumped

seawater down through the casing as it is lowered.

The permanent guidebase creates a four guideline system which is used to drill the hole for the 20-inch

structural casing. This operation can be done with or without the drilling riser, as shown in Figure 24. If the

returns are not brought to the surface, consideration must be given to possible interference problems with

the return pile that will be created around the wellhead. The running of the 20-inch casing, as shown in

Figure 25, establishes the wellhead on which the BOP is landed.

In guidelineless systems, the temporary guidebase is typically run on the hole opener for the 30-inch

surface casing as shown in Figure 26. Note the acoustic targets on the guidebase. The 30-inch casing with

the permanent guidebase attached is lowered into and through the temporary base by use of the acoustic

location system and a wireline sonar and T.V. tool located at the bottom of the 30-inch as shown in Figure

27. The long baseline acoustic system gets the vessel over the target, while the ultra-short baseline sonar

guides the casing towards the acoustic targets on the temporary base. The camera system then is used to

stab the casing into the well guide.

The 30-inch casing can be directly jetted into the seafloor, as shown in Figure 28 if the soils are appropriate.

This avoids use of the temporary guidebase.

The 20-inch casing is run in a similar manner as shown in Figure 29. This establishes the wellhead on

which the BOP is landed using similar guidance.

4.2.3 Motion Compensation Systems

Relative motion must be accommodated in the riser, guideline and drill pipe systems. The drill pipe

compensation system is usually designed into the drawworks, as shown in Figure 30. The riser and

guidelines systems use external compensators called tensioners, as shown in Figure 31.

A riser on a floating rig is supported by axial tension applied to the top of the riser and possibly by buoyancy

along the length of the riser. Tension controls the stress level in the riser pipe and affects the riser

straightness during drilling operations. As rise size, water depth, sea conditions, mud weights, etc.

increase, the axial tension requirements for providing proper support also increase. A rough order of

magnitude of the nominal tension required to maintain the bottom joint of the riser in positive tension is:

T nominal = (weight of riser in water + weight of drilling fluid in water) x 1.20.

Standard tensioner sizes utilized today are 60,000 lbs. or 80,000 lbs. per tensioner. These units are utilized

in systems containing 4 to 10 tensioners. Riser tensioners are operated in pairs so that the two tensioners

connected on diagonally opposed sides of the riser are always at the same tension level. Additional pairs of


Updated Dec. 1999

tensioners are used to achieve both redundancy of tension availability and high levels of tension by utilizing

all the tensioners on the riser at the same time. A well designed system will provide the maximum required

tension level with at least one tensioner out of service.

The tensioner wireline travel or motion compensation capability must exceed the maximum vessel heave

expected to occur while the riser is connected to the wellhead. The tensioner motion capacity must not

only exceed vessel heave but must also account for tidal motion, connection adjustment, and changes in

vessel ballast position. Excessive travel requirements will normally be detrimental to overall operational

efficiency of any tensioner. The tensioner must have the capability to respond at the maximum peak

response of rig vertical heave motion. This response must equal or exceed the instantaneous maximum

vertical speed of the vessel heave, which exceeds the average vertical speed of the vessel.

Presently available tensioners create linear force in a hydraulic-pneumatic cylinder/ram by application of

high pressure compressed air, as illustrated in Figure 32.

This linear force is transmitted by a wire rope to the top of the marine riser to provide axial tension. One end

of the wirerope is connected to the tensioner or rig and the other end is reeved across an idler sheave and to

the top of the marine riser. Force in the cylinder is thus translated to wirerope tension and then to tension in

the riser. Air pressure is maintained at an approximately fixed level to maintain the desired tension level in

the riser. As the rig heaves upward, the top of the marine riser remains fixed (as it is fixed to the earth by

being connected to the wellhead).

Wellhead guidelines must also be taut to be effective. In order to maintain guidelines taut at a preselected

tension level, hydra-pneumatic tensioners are applied to each of the four wellhead guidelines and normally to

the blowout preventer control lines. Guideline tensioners operate exactly the same as riser tensioners and

are designed the same, except they are smaller in size. Figure 33 illustrates their operation.

The major application for a drill string compensator (DSC) is to nullify rig heave that would be imposed on

the drill string. This motion nullification significantly improves the operation of the following procedures:

• Maintain a virtually constant bit weight

• Permit a relatively soft landing of the BOP stack and/or marine riser

• Permit safe landing of casing

• Eliminate the motion of the drill string in the BOP stack

• Eliminate drill string motion during many operations (e.g., landing a subsea tree).

All present drilling rig DSC’s are an air spring tensioning device. They are passive devices that function

based on the difference in the suspended weight of the drill string and the tension level set in the DSC.

During drilling, the drill string weight is supported by the hydraulic-pneumatic cylinder of the DSC and the

drill bit weight on the bottom. The cylinders are interconnected to the air pressure vessels (the same as the


Updated Dec. 1999

riser tensioners). Control of the air pressure in the air pressure vessels determines the tension level. Proper

DSC drilling techniques always require a DSC tension setting to be less than the weight of the drill string.

There are two basic types of DSC’s: motion compensate the crown block, or the traveling block.

A crown block DSC, shown in Figure 34, is a tensioning device that supports the crown block and thus the

drill string. By supporting the crown block with controlled tension, the compensator becomes a motion

nullification device by raising and lowering the crown block. This then raises and lowers the traveling block

and hook to nullify motion or to isolate rig motion from the drill string.

A traveling block DSC, as shown in Figure 35, is connected between the traveling block and the hook. Its

tension level is controlled by techniques identical to a riser tensioner. The tension device can be either a

tension type or a compression type.


Updated Dec. 1999

WELL COMPLETION

TABLE OF CONTENTS

1.0 CASING DESIGN AND CONNECTORS................................................................................... 1

1.1 Casing Strings .............................................................................................. 1

1.1.1 Caisson.................................................................................................. 1

1.1.2 Conductor Pipe ....................................................................................... 1

1.1.3 Surface Casing........................................................................................ 1

1.1.4 Production Casing ................................................................................... 2

1.1.5 Protective Casing .................................................................................... 2

1.1.6 Liners ..................................................................................................... 2

1.1.7 Tubing .................................................................................................... 2

1.2 Special Design Considerations ....................................................................... 2

1.2.1 “Sour” Production .................................................................................... 2

1.2.2 Thermal Casing Design ............................................................................ 3

1.2.3 Directional Well Design............................................................................ 3

1.3 Imposed Design Parameters........................................................................... 3

1.3.1 Depth..................................................................................................... 3

1.3.2 Size 3

1.3.3 Pressures......................................................................................................... 3

1.3.4 Type of Well ..................................................................................................... 3

1.4 Reference Standards and Codes ..................................................................... 4

1.5 Design Criteria .............................................................................................. 4

1.5.1 Conventional Criteria ................................................................................ 4

1.5.2 Optional Criteria ...................................................................................... 4

1.5.3 Special Criteria........................................................................................ 4

1.5.4 Design Factors........................................................................................ 5

1.5.5 Types of Loads........................................................................................ 5

1.5.6 Other Load Considerations. ...................................................................... 5

1.6 Methods of Designing Casing ......................................................................... 6

1.6.1 Arithmetical Methods ............................................................................... 6

1.6.2 Design Chart Methods ............................................................................. 6

1.6.3 Computer Methods .................................................................................. 6

1.6.4 Pre-Calculated Quick Design Charts ......................................................... 6



Updated Dec. 1999

1.7 Connectors ................................................................................................... 6

1.7.1 Round Thread.......................................................................................... 7

1.7.2 Buttress Thread....................................................................................... 7

1.7.3 Extreme Line .......................................................................................... 7

2.0 WELLHEADS - PLATFORM AND SUBSEA ............................................................................ 8

2.1 Platform Wellheads ....................................................................................... 8

2.1.1 Typical Wellhead..................................................................................... 8

2.1.2 Design Working Pressures ....................................................................... 8

2.1.3 Other Design Considerations .................................................................... 9

2.1.4 Casing Heads ......................................................................................... 9

2.1.5 Casing Head Spools (“Braden Head”) .................................................................. 9

2.1.6. Casing Hangers (“Slips”) ................................................................................... 9

2.1.7. Tubing Head Spools ......................................................................................... 9

2.1.8. Tubing Hangers ............................................................................................... 10

2.2 Subsea Wellheads ....................................................................................... 10

2.2.1 Wet Tree Completion .............................................................................. 10

2.2.2 Marine Wellheads................................................................................... 10

2.2.3 High Pressure Housing ........................................................................... 10

2.2.4 Completion Riser.................................................................................... 10

2.2.5 H-4 Connector........................................................................................ 11

3.0 TUBING PACKERS.............................................................................................................. 12

3.1 Purposes for Production Packers ................................................................... 12

3.2 Types of Packers ......................................................................................... 12

3.2.1 Hookwall Packers................................................................................... 12

3.2.2 Anchor Packers ..................................................................................... 13

3.2.3 Cup Packers .......................................................................................... 13

3.2.4 Inflatable Packers ................................................................................... 13

3.3 Methods for Setting the Packers .................................................................... 13

3.3.1 Mechanical Set Packers ......................................................................... 13

3.3.2 Hydraulic Set Packers ............................................................................ 13

3.3.3 Electrically Set Packers.......................................................................... 14

3.3.4 Setting Anchor Packers .......................................................................... 14


3.4 Description of Packer Components ................................................................ 14

3.4.1 Mandrels ............................................................................................... 14


Updated Dec. 1999

3.4.2 Seals .................................................................................................... 14

3.4.3 Slips ..................................................................................................... 14

3.4.4 By-Pass ................................................................................................ 15

3.4.5 Hybrid Packers ...................................................................................... 15

3.4.6 Multiple Packers .................................................................................... 15

3.4.7 Packer Accessories ............................................................................... 15

3.5 Packer Materials .......................................................................................... 16

3.5.1 Metal Components ................................................................................. 16

3.5.2 Heat Treatment ...................................................................................... 16

3.5.3 Seals .................................................................................................... 17

3.5.4 Plastic Coating....................................................................................... 17

3.5.5 Sour Gas Service ................................................................................... 17

4.0 DOWNHOLE SAFETY VALVES ............................................................................................ 19

4.1 Velocity Type DHSV..................................................................................... 19

4.2 Ball and Clapper Type DHSV’s ...................................................................... 19

4.2.1 Wireline Retrievable ................................................................................ 19

4.2.2 Tubing Retrievable .................................................................................. 19

4.2.3 Balanced Type DHSV’s........................................................................... 20


Updated Dec. 1999

LIST OF FIGURES

FIGURE 1. Typical Casing Programs

FIGURE 2. Engagement Illustration

FIGURE 3. Typical Wellhead Assembly

FIGURE 4. Typical Platform Wellhead Assembly

FIGURE 5. Christmas Tree Assemblies

FIGURE 6. Casing Heads

FIGURE 7. Casing Spools

FIGURE 8. Casing Hangers

FIGURE 9. N Tubing Spool

FIGURE 10. Tubing Hangers

FIGURE 11. Xmas Tree in Production Mode

FIGURE 12. Cross-Section of Seafloor Completion

FIGURE 13. Marine Wellhead Stack-ups

FIGURE 14. Wellhead Assembly for a Two Stack System

FIGURE 15. SG-5 High Pressure Housing

FIGURE 16. Completion Riser

FIGURE 17. Running Tubing

FIGURE 18. Vetco H-4 Connector

FIGURE 19. Retainer Type Hookwall Packer

FIGURE 20. Mandrel Type Hookwall Packer

FIGURE 21. Anchor Packer

FIGURE 22. Cup Packer

FIGURE 23. Inflatable Packer

FIGURE 24. Mechanically Set Packer

FIGURE 25. Otis Type F Pressure - Differential DHSV (Storm Choke)

FIGURE 26. Wireline Retrievable Flapper and Ball Type DHSV’s

FIGURE 27. Tubing Retrievable Flapper and Ball Type DHSV’s

FIGURE 28. Balance Type DHSV


Updated Dec. 1999

LIST OF TABLES

TABLE 1. Summary of Casting Design Criteria

TABLE 2. Typical Casing Design Factors

TABLE 3. Reasons for Using Production Packers


Updated Dec. 1999

1.0 CASING DESIGN AND CONNECTORS

The purpose of a well casing program is to provide a secure conduit for either producing or injecting well

fluids. A properly designed casing program will allow drilling and completing the well safely and

economically. Minimum risk to the environment, personnel, groundwater zones, and the penetrated

reservoir zones will be accomplished by appropriate consideration of design parameters. Application of

accepted industry standards and operating procedures will assure that the fluid conduit will perform for the

long periods of time required for most commercial applications.

1.1 Casing Strings

Several types of casing string arrangements are possible depending on the specific needs. Some strings

are common to all types of completions, but some other types of strings may be used only as required by

special circumstances. Typical casing string arrangements are shown in Figure 1 for a normally (hydro)

pressured well and for a geo-pressured well (one in which tectonic conditions have resulted in formation

pressures above normal pressures).

1.1.1 Caisson

A normal offshore platform well will include a caisson that is usually 30 inches O.D. This conductor is driven

into the sea bottom to allow spudding the well. In recent years, curved conductors have been used to help

maximize horizontal reach for the directionally drilled wells.

1.1.2 Conductor Pipe

The conductor pipe is the first string that is run and cemented. For offshore wells, it is usually run to 1000

feet deep and it can be from 7 to 30 inches in diameter. For most offshore wells, the conductor is usually

20 inches O.D. and cemented as deep as 1000 feet. This string provides a fluid course for deeper drilling by

casing off the shallow unconsolidated formations. It is commonly cemented back to the surface and

occasionally the cemented conductor pipe acts as a support for the well.

1.1.3 Surface Casing

The surface casing can vary in depth from a few hundred feet to more than 4000 feet. It can act as the

foundation pile if this function is not provided by the conductor pipe. Also, the surface casing protects the

freshwater sands from contamination by wellbore fluids. Sizes typically vary from 7 to 16 inches with 10-3/4

and 13-3/8 inches being the most commonly used. For offshore directionally drilled wells, the cement top is

limited to the kick-off point to simplify platform abandonment.


Updated Dec. 1999

1.1.4 Production Casing

For normally pressured wells, drilling can proceed without the need of further casing provided normal mud

weights can be used (up to about 12 ppg). If lost circulation zones exist, special considerations may be

necessary to minimize drilling problems. Once the well is drilled through the interval to be completed, the

production string is set. Sizes vary from 2-3/8 through 9-5/8 inches and extend to or through the producing

formations. These strings are cemented to an adequate distance above the producing formation. This may

be established by regulations and usually is about 1000 feet. However, this string is sometimes cemented

back to the surface.

1.1.5 Protective Casing

If geopressures are encountered, high weight mud must be used to control the well. This requires installing

a protective string to prevent losing returns to shallower formations. These strings vary from 7,000 feet to as

much as 15,000 feet in length. Large pipe of 7 inches to 11-3/4 inches is used. At least the lower 1000 feet

of the string is cemented and it is hung from the surface casing head housing. Longer cement intervals are

frequently used to prevent buckling.

1.1.6 Liners

If the abnormal pressure increases at depth such that the fracture pressure of the shallower abnormal

pressure zones is exceeded, the shallower zones must be cased off to prevent loss of circulation. The

protective string is then extended with a liner. The liners are usually cemented full length, with 5-inch and 7-

inch sizes being common.

1.1.7 Tubing

The tubing string is installed to allow handling well fluids through a removable conduit. This conduit protects

the casing strings from erosion and corrosion damage, which is important because the casing strings

cannot be removed if they are damaged. Tubing size is selected based on the rates which must be

handled.

1.2 Special Design Considerations

Circumstances may exist which require that special design needs must be met.

1.2.1 “Sour” Production

If H2S gas is encountered in the produced fluids, the production can be “sour”. This is the term given to fluid

streams containing hydrogen sulfide gas. If the concentration exceeds an H2S partial pressure of 0.001

atmosphere, tubular steel must be selected to have a specific cracking susceptibility value (10 minimum).


Updated Dec. 1999

This normally requires a Rockwell C hardness of less than RC22 which limits the ultimate strength to about

100,000 psi. API grade C-75 and L-80 casing are manufactured especially for this service and a C-90 grade

is being developed.

1.2.2 Thermal Casing Design

Whenever unusually high or low temperature conditions can exist during either normal producing operations,

well killing operations, or workover conditions, the casing/tubing designs must account for the thermal

expansions and contractions which will occur. If the design does not account for these conditions, large

thermal stresses can result and failure is almost certainly assured.

1.2.3 Directional Well Design

The doglegs in directional wells bend the casing and induce added axial stress. Except for the larger

casings, this is usually not critical. API Bulletin 5C4 is available to provide design guidance for this effect on

tension. Also, the casing tends to deform (oval) when bent. This reduces its collapse resistance and must

be considered.

1.3 Imposed Design Parameters

To assure success of the casing design, certain information must be determined based on the best

information available. It is important not to overdesign because of the high cost of overdesigning.

Conversely, cost consequences of failure due to underdesign are unacceptable.

1.3.1 Depth

The well depth objectives can usually be predetermined to within a few hundred feet. This is done through

subsurface and seismic control techniques.

1.3.2 Size

The tubing size is established on the basis of design rates and acceptable pressures. Deep wells with high

rates will require large tubing sizes. The casing sizes are determined to accommodate the tubing without

“running out of hole” before reaching depth. Deeper wells will require larger casing programs.

1.3.3 Pressures

Casing design pressures include both those imposed by the drilling mud gradients and the well fluid

gradients.


Updated Dec. 1999

1.3.4 Type of Well

The casing design should consider the type of well being drilled. If it is a development well with a high

change of success, the design should be conservative without being wasteful. If the well is an exploratory

well, the design should be minimal because of the low change of success. This design requires

considerable judgement on the part of the operator because the cost consequences of losing control of an

exploratory well can be many times the cost savings resulting from a minimal design.

1.4 Reference Standards and Codes

A listing of useful references for casing designs follows. The latest edition of these references should

always be used.

API Spec 5A - Casing, Tubing and Drill Pipe (March 1973)

API Spec 5AC - Restricted Yield Strength Casing and Tubing (March 1975)

API Spec 5AX - High-Strength Casing, Tubing and Drill Pipe (March 1973)

API Spec 5B - Threading, Gaging, and Thread Inspection of Casing, Tubing, and Line

Pipe Threads (April 1971)

API RP 5C1 - Care and Use of Casing Tubing (March 1973)

API Bulletin 5C2 - Performance Properties of Casing, Tubing, and Drill Pipe (March 1975)

API Bulletin 5C3 - Formulas and Calculations for Casing, Tubing, Drill Pipe, and Line Pipe

Properties (November 1974)

API Bulletin 5C4 - Round Thread Casing Joint Strength with Combined Internal Pressure

and Bending (April 1972)

1.5 Design Criteria

Casing string design criteria depends on environmental conditions which determine the loading, the

assumptions that are made about how these loads shall be calculated, and the design factor. Three

possible groups of criteria should be considered. These include conventional criteria, optional criteria, and

special criteria as summarized on Table 1.

1.5.1 Conventional Criteria

These criteria will apply for most casing designs including low to medium pressures and shallow to medium

depth wells. The criteria include effects of buoyancy but generally neglect axial load effects.

1.5.2 Optional Criteria

These criteria are intended for high pressured deep casing designs. More thorough analysis of loads and

their interactions on designs are warranted. Buoyancy, effect of tension on burst, and the effect of


Updated Dec. 1999

evacuation on axial load are considered.

1.5.3 Special Criteria

Sometimes even more specific analysis warranted. These criteria are directed to those special wells and

include considerations for triaxial stress analysis, thermal stresses, and temperature effects.

1.5.4 Design Factors

Factors of safety are used in all engineering designs. These factors are used to allow for conditions which

methods of calculation are not available, such as uncertainties of materials strength or loading conditions.

Use of factors of safety for casing design can reduce the complexities of the designs. However, because

numerous simplifying assumptions are made, the resulting factors are not true factors of safety as the term

normally implies. They are actually design factors which can be applied to assure that resulting designs are

adequate with confidence that safety levels are acceptable. Typical design factors are shown on Table 2.

Engineering judgement can be used to determine which type of design factors should be applied.

Regardless of the type that is used, the designer should be confident that casing design integrity results.

1.5.5 Types of Loads

A casing string must be designed for basic tension, burst, and collapse loads. Also, if they can occur,

loads due to bending, buckling, acceleration, or torque must be considered.

The tension design must allow the casing string to be run into the well without parting. The casing string

must be capable of withstanding any internal pressures that exist during drilling or producing operations.

Also, the casing string must be able to withstand external collapse pressures which can exist if the

pressure inside the casing is reduced or when the casing is immersed in well fluid. If combinations of

tension, burst, or collapse can exist simultaneously, the casing design must consider these interactive

loads. When appropriate, possible buckling failure should be considered.

1.5.6 Other Load Considerations.

A casing string may also be exposed to other loading conditions which should be considered.

Slip crushing at the wellhead slip area is possible because the casing is subjected to severe collapsing

loads. Controlled friction slips can be used to keep the strain from these loads within drift tolerance for most

casing strings. Heavy casing strings should be reviewed carefully. For normal drilling practices, it is

common to install the uppermost “gage” joint which is as heavy as the heaviest weight of casing in the

string. This will assure adequate collapse resistance of the casing.

The effects of temperature changes should be considered. Very large tensile or compressive stresses can


Updated Dec. 1999

be imposed on the tubing string because it is fixed at both ends of the casing string.

Surface casing is subjected to large compression loads just below the wellhead. All of the hanging weights

of the protective or production string is transmitted to the earth through the surface casing. If large loading

circumstances warrant, the stability of the surface casing as a freestanding column should be checked.

Drilling wear of the casing string (or key “seating”) can be caused by the drill pipe rotation. If this wear can

be quantified, reduction in burst or collapse pressure should be considered.

Perforating the casings can damage the casing and reduce its collapse strength. Appropriate perforating

techniques is the best method to use to prevent this from becoming a problem.

Corrosion can be caused by produced fluids or groundwater. If necessary to assure long term casing

integrity, appropriate corrosion allowances or protective measures may be necessary.

During some cementing processes, the casing is rotated rather than reciprocated. This can place a large

torque on the casing and its joint. The torque value should not be allowed to exceed the make-up torque

value for the connections. Sometimes, rotating torque requirements can be reduced by using a combination

of lowering and torquing the string.

1.6 Methods of Designing Casing

Four methods can be used to design a casing string. These are arithmetical, graphical or design charts,

computer design, or pre-calculated quick design charts.

1.6.1 Arithmetical Methods

These methods are tedious and time-consuming compared to design chart methods. Thus, it is rarely used.

1.6.2 Design Chart Methods

These methods are frequently used, especially if computer facilities are not available. The design chart

method is frequently used as a learning tool to demonstrate how the computer methods work.

1.6.3 Computer Methods

Once the designer understands how to apply the proper design methods, the computer is the best way to

perform many complex casing designs quickly and easily.

1.6.4 Pre-Calculated Quick Design Charts

Their use tend to inflate casing costs because they are usually based on loads which are greater than

necessary. They can be used when necessary, but designs are usually very conservative.


Updated Dec. 1999

1.7 Connectors

Three types of API joints are typically used for casing connectors. As shown on Figure 2, these include

round thread, buttress thread, and extreme line connectors.

1.7.1 Round Thread

The connector is threaded and coupled with conventional rounded crest and root V-type 8 pitch threads

tapered ¾ inch per foot on diameter.

1.7.2 Buttress Thread

The connector is threaded and coupled with special buttress form 5 pitch threads tapered ¾ inch per foot on

diameter.

1.7.3 Extreme Line

The connector is an integral type joint with special modified acme form threads and a specially designed

positive metal-to-metal pressure seal.

Table 2 TYPICAL CASING DESIGN FACTORS

COMMONLY USED

DESIGN FACTORS

LESS CONSERVATIVE

DESIGN FACTORS

tension without burst loading - 1.6 tension - 1.5

tension with burst loading - 1.2

burst - 1.33 burst 1.25

collapse - 1.0 collapse 1.0


Updated Dec. 1999

2.0 WELLHEADS - PLATFORM AND SUBSEA

Wellhead equipment includes items that are installed permanently on the well at the surface. This

equipment is used to control pressure during the drilling operations and producing life of the well. Wellhead

items typically include casing heads, tubing heads, hangers, valves, chokes, fittings, and associated parts

as shown on Figure 3. Although every well is equipped with a wellhead, components may vary extensively

from one well to the next depending on service needs, application requirements, and operator preference.

2.1 Platform Wellheads

Offshore wellhead designs will usually incorporate many common features. Figure 4 shows a typical

offshore platform wellhead assembly. Brief discussions of major components follows:

2.1.1 Typical Wellhead

The tubing/tubing hanger equipment provides the pressure tight producing conduit from the producing zone

to the surface. A manually operated master valve is mounted immediately on top of the tubing string, with

an operated master valve immediately above the manual master. A flow fitting allows mounting a swab valve

on top of the operated master valve and choke and manual wing valve to the side. This arrangement allows

access to the tubing string for wireline work and positive isolation for operated valve testing/repair or choke

size changing.

Immediately below the tubing master, a side annulus access valve is provided. The most common function

for this is to allow checking for tubing/packer failure or gas lifting. Also located in this section is the ¼ inch

control line penetration to the downhole safety valve (DHSV).

An additional valve is located below the production annulus valve to provide annulus access between the

surface casing and protective casing. Normally, this is only used to monitor for downhole failures.

2.1.2 Design Working Pressures

Wellhead working pressure rating must be greater than the maximum expected operating pressures.

Wellhead working pressures and pressure testing requirements are defined in API Spec 6A as follows:

Working Pressure (PSI) 2,000 3,000 5,000 10,000 15,000 20,000

Test Pressure (PSI) 4,000 6,000 10,000 15,000 22,500 30,000

It is not uncommon for the working pressure rating to vary from the bottom to the top of tree. For example, a

3000 psi casing head can crossover to a 5000 psi tubing head and master valve. This is acceptable since

the lower portion of the wellhead may be subjected to lower pressure conditions. Crossover seals must be


Updated Dec. 1999

used to isolate the lower pressure equipment from the higher pressure equipment.

The casing head is selected to withstand the maximum pressure which will be encountered during drilling.

Its working pressure should be only somewhat above the casing burst pressure. The casing head also

serves as a support for BOP drilling equipment.

2.1.3 Other Design Considerations

The effect of temperature should be accommodated. API Spec 6A identifies applicable steel parts for

temperatures between -20° and 250°F. this range should handle the vast majority of wells.

Materials should be selected in accordance with API 6A and the product should be obtained from an API

qualified manufacturer. Close evaluation will be necessary only for special applications. If CO2 content

exceeds more than about 15 psi partial pressure, 410 stainless should be used unless H2S is present. 316

stainless may then be a better choice.

Wellheads and components should be coated to prevent rusting. Several acceptable coating

systems/methods have been applied successfully.

If the well heads are located on a congested, manned platform, wellhead selection should consider integrity

under fire conditions for a few hours. This choice may result in either the saving or loss of major

investments.

A brief summary follows of typical major wellhead components as shown in Figure 5.

2.1.4 Casing Heads

A casing head, as shown in Figure 6, should be installed on the first string of casing which requires blow-out

preventers for further drilling. Connection to the casing can be either by a female thread or a slip-on welding

connection. The latter eliminates space-out problems but requires availability of a welder.

2.1.5 Casing Head Spools (“Braden Head”)

A casing head spool, as shown in Figure 7, is normally used for the running and hanging of each additional

casing string. Careful attention to crossover connections and pressure ratings must be given.

2.1.6. Casing Hangers (“Slips”)

Casing hangers, as shown in Figure 8, are required for all subsequent strings of casing after installation of

the casing head housing. The hanger supports and centralizes the inner string and provides a seal between

the two strings. The hanger must be designed not to mash or crimp the inner string. Careful attention

must be given to this area and consideration provided for getting the casing through the BOP, landing, and


Updated Dec. 1999

energizing the seal.

2.1.7. Tubing Head Spools

Design of the tubing head spool, as shown in Figure 9, is much like that of the casing head spool. The

bottom flange must be the same size and rating of the mating flange.

2.1.8. Tubing Hangers

The most suitable all around hanger is the mandrel type, as shown in Figure 10, that is internally prepared

for a back pressure valve. They should be threaded with the same thread on bottom as the tubing joint. The

top thread should normally be EUE and the mandrel size and type must be compatible with the tubing head

spool.

2.2 Subsea Wellheads

The functional requirements for a subsea wellhead are the same as those for a platform wellhead. However,

where platform equipment is in a “hands on” location, a subsea wellhead must be installed remotely on the

seafloor.

2.2.1 Wet Tree Completion

A typical wet tree subsea diverless system is shown on Figure 11. This particular arrangement is equipped

for through flowline (TFL) operations. TFL permits performing many of the downhole operations which would

normally be done by wireline methods if the wellhead were located on a platform.

A cross-section of the seafloor completion is shown on Figure 12. As evident from this figure, although the

functional needs for the platform and subsea wellheads are similar, the methods for meeting these needs

are quite different.

2.2.2 Marine Wellheads

Numerous marine wellhead stack-ups are possible and some of these arrangements are shown of Figure 13.

When ever the completion needs can be met with a single stack system, it is best to do so. Dual stack

arrangements require that two subsea BOP’s and marine drilling risers be used. This is not desirable from a

drilling standpoint.

An extended view of two stack wellhead assembly is shown on Figure 14. This information demonstrates

the interfaces between the temporary guidebase, permanent guide structure, low pressure wellhead housing,

high pressure wellhead housing, and the two casing hanger assemblies.


Updated Dec. 1999

2.2.3 High Pressure Housing

A Vetco SG-5 high pressure housing system for 13-3/8 inch/9-5/8 inch/7 inch casing strings is shown on

Figure 15. This arrangement reveals the intricate mechanisms which must be interfaced remotely during the

well drilling operations.

2.2.4 Completion Riser

After setting the final casing string, the well is ready for running the tubing string(s). This is done with a

completion riser, as shown in Figure 16. The tubing and tubing hanger is run as shown on Figure 17,

landed, and locked into place.

2.2.5 H-4 Connector

In the Vetco System, the means for positively connecting the marine riser and tree to the wellhead is an H-4

connector as shown on Figure 18. The final arrangement can be seen on Figures 11 and 12.


Updated Dec. 1999

3.0 TUBING PACKERS

Packers are used to provide a downhole seal between tubular strings. They are most frequently used to

provide a seal between the production tubing(s) and the production casing or between injection tubing(s) and

the protective casing. Also, packers can be used to provide a seal between a liner and casing or between

two strings of protective casing.

3.1 Purposes for Production Packers

There are several operating reasons for needing to provide a seal in the tubing-casing annulus. A summary

is provided on Table 3.

Sometimes, regulatory requirements demand that a packer be used for production, injection, or salt water

disposal wells. When warranted by conditions or sound engineering principles, waivers can usually be

obtained.

3.2 Types of Packers

Several types of packers are available. There are both many manufacturers and many basic designs for the

packers. For more detailed information, literature of Baker Oil Tools, Brown Oil Tools, Guiberson Division-

Dresser Industries, Halliburton Services, Otis Engineering, and Texas Iron Works can be reviewed.

Basically, designs are for hookwall packers, anchor packers, cup packers, and inflatable packers.

3.2.1 Hookwall Packers

Hookwall packers are the most frequently used packer types. As shown in Figures 19 and 20, it depends

on slips to engage the casing which develops the capability to resist forces imposed on the packer and

allows the pressure seal to be effected.

Hookwall packers can be set mechanically, hydraulically, or on an electric line. The setting procedure

causes the slips to move outward along an inclined plane to engage the casing. The inclined plane is

usually called a cone because of its circular configuration. Continued movement between the packer

mandrel and body compresses the resilient seal to effect the pressure seal. Seal compression is

maintained by weight applied from the tubing string, tension pulled in the tubing string, or opposing slips.

The hookwall packers are either the retainer type, as shown in Figure 19, or the mandrel type as shown in

Figure 20. The retainer type allows independently pulling the tubing. The tubing connects to and is an

integral part of the tubing string. Retainer type packers may either be drillable or retrievable. The drillable

type are called permanent packers and must be destroyed, destructively retrieved, or destructively released

and pushed to bottom. Mandrel type packers are designed to be retrievable. Release is accomplished by


Updated Dec. 1999

manipulation of the packer to slide the inclined plane (cone) from beneath the slips.

3.2.2 Anchor Packers

Anchor Packers, as shown in Figure 21, require support from some other well component. When the

supporting member has been contacted, additional weight compresses and expands the seal into contact

with the casing. The additional weight must be maintained on anchor packers in production service to keep

an effective seal. Anchor packers are relatively inexpensive and are especially advantageous for low

pressure, multiple completion applications.

3.2.3 Cup Packers

Cup Packers are run with the seals in contact with the casing. There are no supporting features other than

the tubulars on which they are run as shown in Figure 22. Differential pressures cause the seals to expand

and conform to the confining casing. Application is usually limited to shallow depths, low differential

pressures, and multiple completions where another packer serves as both a separation packer and a

support for the cup packer.

3.2.4 Inflatable Packers

The inflatable packer has a seal which may be expanded with pumped liquids to contact the casing as

shown in Figure 23. A check valve system is used to confine the inflating liquids in the packer. The packer

can be released by tubing movement to release the confined liquids. Inflatable packers can provide a more

positive seal for open hole completions.

3.3 Methods for Setting the Packers

3.3.1 Mechanical Set Packers

Mechanical set packers are actuated by manipulation of the drill pipe or work tubing, either rotation or

reciprocation. Drag blocks or springs, which ride the wall of the casing and allow rotational motion or

vertical travel between the packer components, provide means of transmitting a sequence of events. A

setting mechanism, which holds the packer in an unset position during placement at the proper depth, is

activated by rotation and/or reciprocation to allow setting the packer. Setting mechanisms are usually of the

jay-latch or split-nut assembly in hookwall packers as shown in Figure 24. The seal is effected by

continuation of the setting procedure until the desired results are obtained. In weight set hookwall packers,

continued “slack-off” will apply tubing load to the packer, thereby applying compression to the packer seal.

In tension set hookwall packers, upward movement of the tubing to a desired strain will compress the seal.


Updated Dec. 1999

3.3.2 Hydraulic Set Packers

Hydraulic set packers are actuated and the seal compressed by liquid pressures. These offer advantage in

directional wells since no tubular movement is required (vertical or rotational); thus, the packer can be set

after the Xmas tree is installed. Also, these are useful for having “buttoned-up” condition while displacing

completion fluid in abnormally pressured wells. Hydraulic set hookwall packers have essentially the same

components as mechanical set hookwall packers (except drag flocks or springs). The setting mechanism

is a hydraulic cylinder which is actuated by plugging the tubulars below the packer and applying pressure

through the tubulars. Forces transmitted by the hydraulic cylinder cause the slips to engage the casing and

compress the seal.

3.3.3 Electrically set Packers

Electrically set packers are run on conductor cables. Surface initiated ignition of a powder charge in a

subsurface setting device actuates the packer and compresses the seal. The final event in the sequence of

setting a wireline packer is release of the setting device, which is then removed from the well bore.

Electrically set packers are retainer type packers (opposed slip hookwall packers).

3.3.4 Setting Anchor Packers

An anchor packer is mechanically set by applying tubing load after the supporting well member has been

contacted. The supporting member may be a stub liner placed in the hole or, more frequently, tailpipe run

below the packer and set on bottom. As weight is set on bottom, a collet moves and snaps over a retaining

ring (or a shear pin is sheared) releasing the packing element. Additional weight compresses the seal. A

modified or hybrid anchor packer may include slips or a hydraulic holddown.

3.4 Description of Packer Components

3.4.1 Mandrels

A mandrel is the tubular member around which the packer is built. This member holds the various

components together and is a component of all packers. The mandrel is connected to and becomes an

integral part of the tubing string in all packers except the retainer type hookwall packer, and therefore, must

be as strong as the tubing.

3.4.2 Seals

Since the primary function of any packer is to provide a seal, this component is found on all packers. Seals

may be run into the well in contact with the casing, i.e., cup packers. Other seals are expanded by

compressive forces or inflated to effect a seal. Most of the sealing elements in the industry are nitrile rubber


Updated Dec. 1999

products, the trade name Hycar being the most familiar. For wells having a temperature beyond the range of

nitrile rubber (350°F) or wells with an adverse fluid composition (alcohol, methanol, sour gas), other seal

elements must be employed.

3.4.3 Slips

Slips are packer components which engage the casing and provide packer support in all hookwall packers.

Slips for retrievable hookwall packers should be heat-treated to a Rockwell hardness grater than the casing

expected to be gripped and should have sufficient surface area hookwall packers must be frangible (break up

easily during milling operations to remove the packer); however, support must be provided until removal of

the packer is desired.

Many retrievable packers depend on hydraulic holddown slips, or buttons, for preventing packer release or

movement resulting from high pressure below the packer. These slips are actuated by pressure within the

tubing or, preferably, from below the seals. Hydraulic holddown slips may be built into the head of the

packer or attached as an accessory in the tubing string immediately above the packer.

3.4.4 By-Pass

A by-pass is an opening or channel which permits fluid movement through the packer during placing or

retrieving operations. An equally important function is that the by-pass serves to equalize the pressure

above and below when attempting to unseat the packer. Before pulling a packer with hydraulic holddown, a

by-pass must be opened to equalize pressure across the holddown slips or buttons.

3.4.5 Hybrid Packers

Packers of one category may have components usually associated with another category; e.g., an anchor

packer on which an abnormal load will be applied may be equipped with slips to support a portion of the

applied load. Such hybrid packers play an important role in the industry.

3.4.6 Multiple Packers

Multiple zone completions may be made with a series of packers permitting production through a single

tubing string or multiple tubing strings with packer(s) having more than one opening. Packers for multiple

completions have secondary mandrels dependent on the number of well zones to be produced

simultaneously through separate tubes. Multiple packers may be designed and built with characteristic

features of single well packer categories. Multiple well packers are normally mandrel type packers and, as

such, are designed to be retrievable.


Updated Dec. 1999

3.4.7 Packer Accessories

Packer accessories are those pieces of equipment which may be run in conjunction with or placed and

removed at selected times to extend the range of packer functions. Some common accessories are

extension tubes, on-off connectors, plugs and flapper valves.

Extension Tubes are four to six foot length, large internal diameter tubular run below drillable retainer type

packers as a part of the total packer assembly. It is of larger diameter than the packer bore, permitting a

spring-loaded catch sleeve on the packer milling tool to pass through the packer and open into the

extension tube. Once the upper slips of the packer are milled through, the packer can be pulled with the

catch sleeve. Special nipples may be run blow the extension tube for testing or for isolating the producing

zone while the well is being pulled. The extension tube, nipples, subs, etc., make up the tail section on a

packer.

On-Off Connector (tubing seal divider) is a device run above an opposed slip hookwall type packer which will

allow removal of the tubing for leak repairs or other problems without disturbing the packer setting.

Plugs are used in conjunction with retainer type packers and are either retrievable or expendable. Plugs

serve to isolate the zone below the packer and protect it from operations being conducted above the packer.

Retrievable packer plugs are installed in the sealing bore (or in the packer tail section) of a retainer type

packer after the packer has been positioned in the well. The retrievable plug may be recovered to allow re-

entry into the zone below the packer.

Expendable plugs are placed in the sealing bore of the packer (or in the packer tail section) and run at the

time the packer is positioned. Upon completion of desired operations, the plug is pushed out of the packer

and allowed to fall to the bottom of the well.

Flapper Valves are spring loaded closures mounted immediately below the sealing bore of a retainer type

packer. The valve is opened and displaced by insertion of the seal assembly run on the tubing string.

Removal of the seal assembly will allow the flapper to close and retain pressure from below the packer. One

of the important uses of a flapper is to isolate formation pressure below the packer while doing work above,

e.g., pulling tubing.

Other devices which should be considered accessories are available and my be attached to the packer for

special application or for localized well problems. Included in this category are a multitude of multiple

completion accessories. Consultation with manufacturer representatives can usually resolve modifications

useful for optimum application of such devices.

3.5 Packer Materials

A brief discussion of packer materials considerations for sweet service (non-H2S) follows:


Updated Dec. 1999

3.5.1 Metal Components

Metal Components of retrievable packers are generally AISI type 4140 steel or equivalent. Selection of this

grade material was made because the chemical composition is compatible with the usual well effluent, the

strength properties are adequate (similar to N-80), and the machinability is excellent. The metal

components of drillable packers are most frequently cast materials because of the frangibility requirement.

3.5.2 Heat Treatment

Heat Treatment is used to control the hardness or wear resistance of components subjected to rigorous

service. In addition, controlled hardness of some components may be desirable because of well effluent

properties. In a sour gas environment where the packer operating temperature exceeds 200°F, the heat

treatment of 4130-4140 steels should be such that the resultant minimum yield of the material should not

exceed 100,000 psi. If the packer operating temperature is below 150°F and the packer is exposed to a

sour service environment, absolute controlled hardness is essential. The above sour gas considerations

may be modified by BRC; therefore, an investigation should be made to review the latest technology. In all

cases, hardness of slips or hydraulic holddown buttons should exceed the hardness of the casing in which

the packer is to be set.

3.5.3 Seals

Seals are usually a nitrile rubber compound. Special seals may be required for elevated temperatures and

are required for sour service environment above 150°F. Seals for sour service above 150°F should consist of

Teflon (or special elastomers). However, at elevated temperatures Teflon (or special compounds) is subject

to deformation and/or flow and must be contained. The containment mechanism usually consists of steel

rings. The steel rings, of course, must be heat treated in accordance with other packer steel components

outlined above.

Seals are available in different durometer hardness specified according to ASTM D1706-6. Although there is

no unit of measurement, readings of 1 to 100 are assigned. Low durometer seals are easily deformed and

should be used in shallow wells where compressive forces may be difficult to achieve. High durometer seals

should be used in deeper, high pressure, high temperature wells where contained forces may tend to

extrude the seal over long periods of time. Some packer manufacturers use multiple seals with low

durometer to insure a seal and high durometer to minimize distortion under high compressive forces. Both

tubing stress conditions and tubing movement at the packer under given conditions should be considered.

Tubing movement data permits accurate selection of the amount of seals needed for retainer type hookwall

packers.


Updated Dec. 1999

3.5.4 Plastic Coating

Plastic Coating is frequently used on packers to provide corrosion protection in water injection and SWD

wells. Corrosive fluids, other than H2S gas, may justify plastic coating protection. Generally, when the

tubing is coated for protection, consideration should be given to coating all packers and accessory

equipment.

3.5.5 Sour Gas Service

A brief list of acceptable packer materials for sour gas serice follows:

API Grade C-75 material (API Specification 5AC, March 1973). C-75 to be Type I with less than 1.7

percent manganese and having a hardness of RC22 or less.

Carbon steels and low alloy steels having a hardness of RC22 or less. Low alloy steels should have a

nickel content less than 1 percent.

300 series stainless steels fully annealed and having a hardness of RC22 or less.

K-Monel hot rolled and age hardened having a hardness of RC35 or less. Cold drawn K-Monel is not

acceptable.

Inconel X-750 having a hardness of RC35 or less.

Stellites and colmonoys - cemented carbides. Base material having a hardness of RC22 or less.

ASTM A-286 having a hardness of RC35 or less.

The following materials are not acceptable for use in most sour service:

400 series stainless steels.

Low alloy carbon steels containing 1 percent nickel or greater.

Rephosphorized and/or resulfurized free machining steels.

Precipitation hardened stainless steels.

Copper base alloys.

Protect Well Casing from Excessive Pressures and Corrosive Well Effluent.

Protect Producing Interval from Unexpected Pressures or from Surging Annular Fluids.

Isolate Producing Zones in Multiple Completions.

Packer can Anchor the Tubing. This can be Quite Important in Rod Pumped Wells.

Allows Swabbing the Well to Initiate Well Flow more Quickly and Economically.

Installing Packers Near the Lower End of the Tubing String can Improve Well Producing Performance During

the Flowing Life.

Stimulation Treatments can be Selectively Placed and casing Protected from Excessive Treating Pressures

by Using Packers.


Updated Dec. 1999

4.0 DOWNHOLE SAFETY VALVES

The need for a safety device in the well producing string(s) of offshore wells is necessary to provide

additional protection for wellhead equipment. This is because of the close proximity of adjacent wells,

crowded conditions on offshore platforms, and the magnitude of losses if failures do occur. Earliest

methods used were to install a wireline retrievable velocity type downhole safety valve (DHSV) in the tubing

string(s). Reliability considerations have led to development of wireline retrievable ball or clapper valves, and

finally tubing retrievable ball or clapper tubing retrievable valves. Also, with increasing water depth, balanced

type DHSV’s have been developed. These safety devices (or combinations of devices) are set well below

the seafloor so that they will fail closed to prevent well fluids from contributing to major surface disasters and

to protect the reservoir.

4.1 Velocity Type DHSV

One type of wireline retrievable velocity type DHSV is shown on Figure 25. This device is usually set near

the lower end of the tubing string for reasons of flow capacity. It operates on the principle of flowing fluid

through a fixed orifice size. As the flow rate increases, the differential across the orifice increases and at a

predetermined rate it overcomes the spring force which holds the valve open. The valve closes and it

remains closed until the pressure is increased on top of the valve. The spring force reopens the valve when

the pressure across it is about equalized. Alternatively, a wireline equalizing prong can be used to reopen

it.

The hostile environment in which this type of DHSV is used, combined with its inherent sizing difficulties has

reduced the application frequency for this type of valve.

4.2 Ball and Clapper Type DHSV’s

4.2.1 Wireline Retrievable

The need for a more reliable DHSV led to development of surface operated DHSV’s. Both ball and clapper

type wireline retrievable DHSV’s are shown on Figure 26.

This type of DHSV has several advantages over the earlier storm chokes, but its reliability is still not

generally acceptable. Also, since the tubing bore is restricted through the DHSV, it can be susceptible to

sand or erosion cutting.

4.2.2 Tubing Retrievable

The tubing retrievable clapper and ball DHSV’s, as shown in Figure 27, have helped to overcome many of the


Updated Dec. 1999

wireline retrievable device shortcomings. They provide full tubing opening, they can be controlled from the

surface, and they are highly reliable.

Both types of DHSV’s are vulnerable to failure. If the flapper or ball is opened with a large pressure

difference across it, it can be broken. Thus, pressure equalizing before opening is very important. Repair

requires pulling the tubing string.

4.2.3 Balanced Type DHSV’s

Deep setting the single control line DHSV requires use of very strong spring systems. This is because the

hydrostatic head in the control line acts against the spring. Smaller springs and possibly better reliability

can be obtained by using a second line, or balance line, as shown on Figure 28. The balance line equalizes

the hydrostatic across the DHSV. This method requires more seal assemblies and two control lines to the

DHSV, and whether improved reliability truly occurs will be established with time. The single line DHSV

manufacturers have successfully tested their DHSV’s to settings several thousand feet deep.


Updated Dec. 1999

SUBSEA TREES AND CONTROLS

TABLE OF CONTENTS

1.0 CATEGORIZATION OF SUBSEA TREES................................................................................ 1

1.1 Function ....................................................................................................... 1

1.2 Rating and Size............................................................................................. 1

1.3 Maintenance and Operation............................................................................ 2

1.4 Installation .................................................................................................... 2

1.5 Location ....................................................................................................... 3

2.0 SUBSEA TREE COMPONENTS............................................................................................. 4

2.1 Wellhead Connector ...................................................................................... 4

2.2 Tieback Adapter ............................................................................................ 4

2.3 Valves .......................................................................................................... 4

2.4 Valve Blocks................................................................................................. 5

2.5 Wye Spool.................................................................................................... 5

2.6 Tree Caps ..................................................................................................... 5

2.7 Flowloops ..................................................................................................... 5

2.8 Flowline Connections ..................................................................................... 6

3.0 CONTROL SYSTEMS ........................................................................................................... 7

3.1 Direct Hydraulic Control Systems ................................................................... 7

3.2 Piloted Hydraulic Control Systems.................................................................. 8

3.3 Sequenced Hydraulic Control Systems............................................................ 9

3.4 Direct Electrohydraulic Control Systems........................................................... 9

3.5 Multiplexed Electrohydraulic Control Systems................................................. 10

3.6 Hybrid Systems ........................................................................................... 11


Updated Dec. 1999

LIST OF FIGURES

FIGURE 1. Simple Schematics of Dual and Single Trees

FIGURE 2. Non-TFL Tree

FIGURE 3. TFL Tree

FIGURE 4. Diver Operated Manual Injection Tree

FIGURE 5. ROV with Tree Intervention Tool Package

FIGURE 6. Running with Guidelineless Tree with Workover Tool

FIGURE 7. Sub-Mudline Completion Systems

FIGURE 8. Wellhead Connectors

FIGURE 9. Vetco H-4 Connector

FIGURE 10. Mudline System with Wellhead Adapter and Casing Hanger Adapter and Tieback Adapter

Installed

FIGURE 11. Gate Valve and Actuator

FIGURE 12. Ball Valve

FIGURE 13. Wye Spool and Diverter

FIGURE 14. Diverters

FIGURE 15. Tree Cap Assembly with Guide Frame

FIGURE 16. Flowline Pull-in, Alignment, and Connection Tool System

FIGURE 17. Open Direct Hydraulic Control with Subsea Dump Valve

FIGURE 18. Discrete Piloted Hydraulic Control

FIGURE 19. Sequential Piloted Hydraulic Control

FIGURE 20. Direct Electrohydraulic Control

FIGURE 21. Electrohydraulic Multiplex Control with Subsea Hydraulic Power Unit

FIGURE 22. Electrohydraulic Multiplex Control


Updated Dec. 1999

1.0 CATEGORIZATION OF SUBSEA TREES

1.1 Function

Like a surface tree, a subsea tree is an assembly of components whose purpose is to contain reservoir

pressure and permit access to the reservoir for maintenance and measurement. The only difference is that

the subsea tree is located underwater.

Subsea trees are used to control gas and/or oil production from a well, or water or gas injection into a well.

The outward appearance is similar for production and injection wells, though the latter tend to be less

complex.

Subsea trees can control dual or single tubing strings. A dual completion tree will have three vertical bores,

one each for the tubing strings and on for vertical access to the annulus. Likewise, a single completion tree

has two vertical bores.

The subsea tree can be configured for only vertical downhole access with conventional wireline tools, or for

both vertical wireline access and Through Flow Line (TFL) access with pumpdown tools. The differences

between wireline and TFL methods will be discussed in a later section. Figure 1 shows simple schematics

of dual and single trees, and TFL and non-TFL trees. Figures 2 and 3 show a dual Non-TFL tree and a dual

TFL tree, respectively. Note the large (5 ft) bend radius flowloops and the wye spool required on the TFL

trees for passage of pumpdown tool strings.

1.2 Rating and Size

The piping and valves on a subsea tree are rated based on the maximum anticipated tubing pressure at the

wellhead. The highest pressure can be due to wellhead shut-in pressure early in the well’s life, or the

combination of reservoir wellhead pressure and TFL pumping pressure. Regardless of source, the tree

components must be designed to withstand the pressure.

Subsea trees typically come in just two rating categories of 5,000 and 10,000 psi. These represent the

maximum operating pressures. An off size rating is possible to design and build (e.g., 15,000 or 7,500 psi),

but is rarely done since it effects numerous components supplied by different vendors.

The subsea tree is rated by its lowest pressure rated component that is exposed to internal pressure. For

example, a tree with a 10,000 psi wellhead connector and 5,000 psi valves is rated at 5,000 psi.

In addition to pressure rating, a subsea tree is typically specified by the tubing size and the number of

vertical bores. For example a 3x3x2 is a tree for two 3 inch tubing strings and a 2 inch annular access

passage (annular access always being the last size given). Actually, the proper way to specify a subsea


Updated Dec. 1999

tree is by the valve size. This is because there are more tubing sizes in different pressure ratings than there

are subsea tree valves.

1.3 Maintenance and Operation

An early subsea tree designation was ‘dry’ versus ‘wet’ maintenance. A dry tree meant the tree was

encapsulated in a one atmosphere chamber for manned intervention using ‘conventional’ tools. Conversely,

a wet tree was not encapsulated, and required intervention by divers/robotics or vertical retrieval and

servicing on the surface. Dry trees are not used today because of the increased confidence in wet tree

systems; also, dry trees posed an obvious human safety hazard most oil companies would rather avoid.

Subsea trees are typically controlled and monitored remotely with the use of a controls system. Controls

systems will be presented in a later section. For specific applications, systems operated by divers can be

suitable. Figure 4 shows a subsea tree configured for diver operation of all tree valving. In this case, the

tree is for a water injection well where rapid actuator response is not needed.

A growing trend is the use of robotics for maintenance and certain operational functions. Specifically,

Remotely Operated Vehicles (ROV’s) are being outfitted with tool systems that can routinely interface with

appropriately equipped subsea trees. The interventions can be mechanical such as turning valve stems, or

hydraulic for direct actuator control (i.e., ‘hot stab’). Figure 5 shows an ROV with a tool package interfacing

with a tree equipped with docking ports for the ROV’s docking arm and hydraulic valves with mechanical

override by the ROV’s manipulator. Note that this tree also design includes a vertically run hydraulic crane

for retrieving/replacing other tree components such as chokes and control pods.

1.4 Installation

Two installation related designations for subsea trees are diver assisted versus diverless, and guideline

versus guidelineless. These designations refer to the installation of the tree on the wellhead and/or to the

connection of the flowline to the tree.

Saturation divers can typically operate to 900 ft water depth; divers have worked deeper for very special

applications but their work efficiency drops off quickly below that depth. Due to the high cost of a saturation

diver spread, and to prove it can be done, diverless subsea trees have been used in shallower depths than

900 ft. For both diver assist and diverless systems, tool systems are run down to the wellhead or tree on

guidelines, and are typically controlled remotely through an umbilical by a surface operator. The principle

purpose of the diver is for back-up if something goes wrong. Hence, the major difference between the two

installation approaches is the cost of assuring that remote systems operate correctly, and/or the cost for

providing non-diver back-up, typically with ROV’s equipped with special work tools.

In deepwater, wells are routinely drilled without use of guidelines to control the running of the BOP and


Updated Dec. 1999

drilling riser. Subsea trees have also been installed without use of guidelines for landing the tree on the

wellhead or for tieing-in the flowlines. Figure 6 shows a guidelineless subsea tree. Note the use of docking

cones to located the tree connector with the wellhead.

1.5 Location

Typically a subsea tree is located on the seafloor. There are cases where the tree needs to be below the

mudline of the seafloor, for instance in iceberg prone areas and in heavily traveled shipping lanes where

anchors could be frequently dropped. For those situations, the tree could be placed in a caisson set below

the mudline. Figure 7 shows two applications. In the first case, the caisson is large enough to place a

more conventionally configured tree; the large caisson hole requires special drilling technology borrowed

from the mining industry. In the second case, the structural casing of the well serves as the caisson

requiring a radically different tree configuration.

Subsea trees can be used on an isolated satellite well, tied back to another facility with flowlines. Or the

tree can be used on a well drilled through a template structure with direct connection to a manifold also

located on the template. A hybrid of these two arrangements is a clustered well system where two or more

wells are drilled as satellites and tied with short flowline ‘jumpers’ to a manifold template located central to

the wells. Functionally the trees are exactly the same; however, components can be arranged differently to

accommodate installation and/or maintenance.


Updated Dec. 1999

2.0 SUBSEA TREE COMPONENTS

2.1 Wellhead Connector

Wellhead connectors are mechanical or hydraulic mechanisms used to lock and seal the tree to the

wellhead. Most trees use hydraulic connectors, although mechanical connectors have their use as a lower

cost alternative when the situation allows. Most connectors have a mechanical release override, even

hydraulic systems. Two of the most common hydraulic types are the collet connector, shown in Figure 8,

and the segmented ring, shown in Figure 9. These connectors are smaller versions of those used on BOP’s

for drilling operations.

2.2 Tieback Adapter

An exploratory well drilled from a jack-up rig supports the casing strings on the seafloor with a mudline

suspension system, using spools to run each casing string up to the BOP on the deck. The casing

hangers for the mudline suspension system are fluted and provide for the annulus space between the casing

strings to directly communicate to the surface. The well is abandoned by sequentially disconnecting and

retrieving each of the casing string spools at the mudline starting with the production string and ending with

the 30 inch, temporarily capping each casing string. In the event the exploratory well is converted to a

subsea completion, a conventional wellhead is installed, and the annulus space between the casing strings

should be sealed. A tieback adapter is connected to either the 20 or 13 3/8 inch casing string at the

mudline and provides a 18 ¾ or 13 5/8 inch wellhead profile respectively. The smaller casing strings are

then tied into the new wellhead with spools. Figure 10 shows a typical mudline suspension system (without

abandonment caps) and tieback adapter with its assorted components.

2.3 Valves

Functionally, there are three types of valves on the tree. The Master Valves are located between the

wellhead connector and the flow loop(s). They serve as the principle control devices for the reservoir. The

Swab Valve(s) are located above the flowloop junction and the top of the tree. They serve as a pressure

containing barrier between the well and the sea. The Wing Valve(s) are located on the flowloop between its

junction with the vertical bore and the flowline connector. They also serve as a pressure containing barrier

between the well and the sea when the flowline is not present or damaged. The wing valves are typically

used as the principle flow control device in order to preserve the master valves.

API 17D specifies that there must be at least two fail-closed pressure barriers along all production (injection)

and annulus access passages between the wellhead and any potentially open port on the tree. Along the

production (injection) flow path (i.e., from wellhead through flowloop), both pressure barriers must be


Updated Dec. 1999

hydraulically operated valves. Along the vertical production (injection) bore (i.e., from wellhead to top of

tree), one pressure barrier must be a hydraulically operated valve. Along any annulus passage, one

pressure barrier must be a hydraulically operated valve. For a practical example, the simplest single

completion tree would have single hydraulically controlled fail-closed master valves on the production

(injection) and annulus access bores, manual swab valves (or wireline crown plugs) on both bores, a single

hydraulically controlled fail-closed wing valve on the production (injection) flowloop, and a manual valve on

the annulus access flow loop.

The two main types of valves used in subsea trees are gate and ball valves. Figure 11 shows an illustration

of a typical gate valve. Newer gate valve designs allow an ROV to remove and replace the actuator portion of

the valve. The ball valve, as shown in Figure 12, is generally not used as a master valve. It is most widely

used in applications where the valve would be opened or closed without flow in the line, and where clean

fluids are expected. The significant advantage of a ball valve is its compact nature, even with a hydraulic

operator. Each manufacturer’s valve has a slightly different design. Subsea valves used in trees should

meet API specifications.

2.4 Valve Blocks

Most subsea trees are configured with composite valve blocks rather than individual valves joined together as

found on surface wells. The block reduces the number on seals and shorten the stackup dimensions. Also

the solid block is stronger in tension and bending than an individual valve body flange. Figure 13 shows two

manufacturers’ composite valve blocks with hydraulically operated gate valves in one, and a plug diverter in

the other illustration.

Valve blocks are made of high strength alloy steels. Special materials such stainless steel are used where

carbon dioxide corrosion is a problem. The high strength alloys are heat-treated to accommodate hydrogen

sulfide problems. Cladding is also used for special corrosion and erosion situations.

2.5 Wye Spool

Subsea trees designed for TFL require wye spools. They provide a controlled radius passage at the junction

of the vertical bore and the flowloop so that pumpdown tools can pass into and out of the tree while still

allowing vertical entry at another time. The wye spool is typically outfitted with a diverting device which

plugs the vertical passage so that pumpdown tools follow the proper passage into the flowloop upon return

through the tree. Figure 14 shows the cutaway of a wye spool with three types of diverters. The plug

diverter usually also serves as a pressure barrier (i.e., a crown plug). The hydraulic flapper is remotely

controlled.


Updated Dec. 1999

2.6 Tree Caps

Tree caps are used to protect the upper running mandrel of the tree and sometimes to seal the vertical

access into the tree. Figure 15 shows a tree cap that includes an interface for the control pod assembly, a

common feature for maintaining the control pod. Some tree caps have been designed to include chokes so

that the choke can replaced without removing the whole tree. Locating subsystems such as the control pod

and choke on the tree cap take advantage of the fact that the cap can be retrieved without killing the well.

2.7 Flowloops

Flowloops on the tree serve to connect the vertical bores of the tree to the typically horizontal flowlines.

Loops must be constructed with a minimum 5 ft radius for TFL applications. Flowloops typically must be

flexed to accommodate the flowline connection mechanism which can require as much as 14 inches.

2.8 Flowline Connections

Flowline connections for satellite wells typically involve alignment of the flowline as well as connection. For

template wells, alignment with the manifold piping is typically provided. Different tool systems are typically

used to pull-in and align a flowline with the tree, and to make the connection between the flowloop and the

flowline. Figure 16 shows a flowline porch with a suite of tools for pulling the flowline into a guide sleeve for

alignment, and a connection tool for joining the flowline and inboard piping together. The connection system

shown can be used with a single satellite well (not shown for clarity), or with a template system of several

wells (dotted lines showing template framing). The individual tools are small for ease in handling, but the

tree is complicated with a large alignment structure to create the bending moments necessary to properly

locate the flowline hub relative to the inboard hub. Other connection systems use massive pull-in tools that

accept a misaligned flowline, and hydraulically rotate it into proper orientation.

The tool used to make up the horizontal connection can be the same regardless of how the flowline is

aligned. Flowline connections can also be made vertical wherein the flowline connection is typically made-

up at the same time as the wellhead connection. This complicates the initial running of the tree, but saves

on special tooling for the flowline connection.


Updated Dec. 1999

3.0 CONTROL SYSTEMS

For subsea production systems a control system principally provides hydraulic fluid to operate remote

actuators. Typically the actuator operates a valve, diverter or choke on trees, manifolds or downhole tubing.

The control system may also collect data and have automated shutdown logic.

Control systems require communication to select a control function and power to actuate it.

Communication is by hydraulic pressure or electric signal. Power to move a subsea actuator comes from

hydraulic fluid provided from a remote source through a high pressure hydraulic line, or from a local low

pressure reservoir powered by an accumulator. Subsea actuators are usually designed to “fail safe” by

automatically placing the well in a preferred control condition if communication, or hydraulic pressure is lost

(e.g., fail-closed valves).

A variety of control systems using different combinations of communication and power are in use. Selection

of the best system depends on the requirements of the specific application. The design criteria for a control

system typically includes the number of remotely controlled actuators, the number of monitored items, the

distance to the surface control station, regulatory requirements (i.e., response time to close a valve), and

environmental constraints (i.e., ability to vent control hydraulic fluids into the sea). Frequently, selection is a

balance of reliability, cost, and flexibility.

There are four basic types of control systems available: 1) direct hydraulic, 2) piloted hydraulic, 3)

sequenced hydraulic, and 4) multiplexed electrohydraulic. Two other types exist: multi-wire electrohydraulic

and hybrid (systems which combine features of the other types). These last two are infrequently used due

to the outdated technology associated with the first and the general absence of applications for the second.

3.1 Direct Hydraulic Control Systems

Direct hydraulic control systems are the simplest types of system. Figure 17 shows the flow schematics

for two typical direct hydraulic control systems. A hydraulic line connects a hydraulic power supply, on the

surface, directly to a valve actuator on the seafloor. One line is used to control each subsea valve. A

subsea valve is operated by opening a surface mimic control panel valve to allow fluid to flow from the

surface power supply unit to the subsea actuator. The subsea valve is returned to its fail safe position by

closing the supply and opening a surface vent port to allow fluid in the hydraulic control line to vent back to

the fluid reservoir (closed system), or out into the sea (open system). A number of design considerations

must be reviewed prior to the implementation of a direct hydraulic control system. Among these are: data

acquisition requirements, the number of control functions required, control distances (vertical and

horizontal), future expansion requirements and topside limitations.

If data acquisition of any type is required, a simple direct hydraulic system will not be suitable. Either a


Updated Dec. 1999

more complex electrohydraulic system will be required or a hybrid system with a basic hydraulic system

coupled with a data acquisition package.

Because each subsea actuator in a direct hydraulic system has a dedicated flow path from the surface, the

number of functions which can be controlled is limited. This is due in part to space and weight associated

with the surface components required for each control function and in part due to interface umbilical size

limitations.

Direct systems are difficult to modify for future system growth unless major new topside components are

added or existing components are extensively modified. As a result, other system types are often superior

technical solutions where future expansion is a concern.

Straight hydraulic control is satisfactory until the distance between the surface station and well becomes

excessive (greater than 3 miles as a general rule). Subsea valve actuators designed to operate with 3000

psi hydraulic fluid may require as much as 2 gallons or more of fluid. To prevent erosion of the subsea valve

seats during opening or closing, the valve must move quickly. Actuation times of 18 sec or less are normal.

When the distance becomes long (due either to vertical or horizontal distances to the well), moving 2

gallons of hydraulic fluid in 18 seconds for both opening and closing requires an impracticality large and

consequently expensive hydraulic line. To address these and other concerns more advanced system types

were developed.

Characteristics of a typical direct hydraulic system candidate are:

Absence of data acquisition requirements

Limited number of control functions

Moderate control distances (3 miles or less)

Shallow water (1500 ft or less)

Limited or no future expansion requirements

Topside space and weight limitations are not major areas of concern

3.2 Piloted Hydraulic Control Systems

Piloted hydraulic control systems use pressure operated pilot valves to direct hydraulic fluid to subsea valve

actuators. Figure 18 is a flow schematic of a piloted hydraulic control system. For relatively short

distances, hydraulic fluid is supplied from the control station to the pilot valves then directly to the remote

valve actuator. For longer distances, an accumulator may be located at the well. A small hydraulic line can

be used to trickle charge the accumulator. Fluid from the accumulator flows via the pilot valves a short

distance to the valve actuators. Use of the accumulator significantly reduces subsea valve response time.


Updated Dec. 1999

Piloted hydraulic control systems utilize a common hydraulic line between the surface and the seafloor well

to supply hydraulic fluid to all functions and one hydraulic signal line per control function for communication.

To operate a valve, pressure is applied to the signal line at the surface for the selected subsea valve. This

pressure activates the pilot valve which allows fluid to flow from the main power supply line or accumulator to

the desired subsea valve.

The pilot system still utilizes a multi-line hydraulic umbilical as in the direct hydraulic system. However,

hydraulic line sizes are reduced and response time is improved over direct only systems. The system is

still relatively simple and is applicable to wells where a few valves are to be controlled individually, no data

acquisition is required and distances are intermediate. The only equipment required in addition to that of a

direct system is a subsea control module to house pilot valves and a local accumulator (is used). Control

distances for piloted systems can extend up to 8 miles before response time begins to suffer appreciably.

Piloted systems suffer similar limitations to direct systems for future expansion and topside weight and

space concerns.

A typical piloted hydraulic system candidate would be:


Limited number of subsea valves requiring control

Control distances which might otherwise preclude use of

A hydraulic only system (3 - 8 miles)

Shallow to medium water depths (up to 1500-2000 ft)

Limited or no future expansion


3.3 Sequenced Hydraulic Control Systems

A sequenced hydraulic control system uses one (or possibly two) hydraulic control line(s) to control all the

functions of a single tree or manifold. Figure 19 shows the flow schematic for a sequenced hydraulic control

system. In this system, one hydraulic line supplies power fluid to the well control module and a second line

provides a hydraulic signal line to a group of pressure actuated pilot valves. Alternatively, signal pressure

may be derived from the main control line or from a spring and the signal line eliminated. Each pilot valve

actuates only a preselected signal pressure. Use of several pilot valves set at different signal pressures

allows control of several subsea valves through one hydraulic line. In operation, the pressure on the signal

line is set to a particular level in a sequence to select the desired pilot valve(s) to actuate the chosen

subsea valve(s).

This system is applicable to wells located long distances from the surface station where multi-line hydraulic

lines would be expensive. The pilot valves on the seafloor are more complex because of the need for a


Updated Dec. 1999

reference pressure (from the signal line or spring discussed above). Seafloor well control systems must

operate reliably without pilot valves and regulators. Thus, the number of sequence positions which can be

reliably used with a 3000 psi hydraulic system is about eight. A 100-200 psi range between each selected

pressure level allows for inaccuracy in the pilot valve setting and for “drift” after the unit is on the seafloor.

With only eight select positions, the number of individual production valves which can be controlled is

limited. A second liability is that once sequencing is designed no operational modifications are possible.

A typical sequenced system candidate would be:


Limited number of control functions (historically a single tree)

Intermediate control distances (3 - 8 miles)

Shallow to medium water depths (500 - 2000 ft)

Limited or no future expansion

Invariable sequence of valve openings for normal operation


3.4 Direct Electrohydraulic Control Systems

Direct E-H systems were the first electrohydraulic systems to be used subsea. As shown in Figure 20,

they require pilot valves, electric signal wires, electric power lines, and hydraulic supply lines. Each electric

function requires a dedicated set of signal wires for data relay. In normal operation, a control function is

fitted with a pilot valve whose solenoids are direct wired to the surface facility. Once a signal is sent to

operate the solenoids the pilot valve opens to route hydraulic fluid to the associated subsea actuator.

Where distances are great, accumulators are located locally to ensure immediate response. In contrast to

hydraulic only systems, data acquisition capability is available on hard-wired systems. This is a major

advantage in today’s market where subsea system monitoring is becoming increasingly important.

Direct, or hard-wired, E-H systems are applicable where minimizing expensive hydraulic control lines is

important and where the number of control functions is small. The major disadvantage is the need for

multiple electric connections between the cable and controls on the wells. In shallow water, it is common to

leave sufficient slack in the cable to allow the subsea controls to be brought to the surface without

disconnecting the cable to obtain maximum connector integrity by making all possible connections dry.

As with MUX E-H systems the topside support components for a hard wire system are lightweight and

compact making the systems ideal for cramped floating production applications.

A typical direct electrohydraulic system candidate would have:

Presence of data acquisition requirements

Intermediate numbers of subsea valves requiring control


Updated Dec. 1999

Short actuation time requirements (18 sec or less)

Deep water developments

Future expansion requirements

Surface facility space/weight limitations

3.5 Multiplexed Electrohydraulic Control Systems

The main difference between a hard-wired E-H system and a MUX system is the elimination of multiple

signal wires in favor of sending a multiplexed signal. The multiplexed signal allows operator selection of a

control function via use of frequency shift keying for each of the various functions to which the multiplexed

signal connected. This multiplexing capability also allows a cost effective means of controlling very large

subsea systems without the incremental cost of signal wires for each controlled function.

A typical MUX system will have a dedicated control module for each major subsea system component (tree,

manifold, chemical injection system, etc.). Because each module in the system has its own address,

future expansions are relatively simple and straightforward. Dependent on its location in the overall system,

the module may be equipped with an accumulator to provide near instantaneous response of valve actuator

to a control signal. Figures 21 and 22 show the flow schematics of MUX E-H control systems with and

without subsea accumulator.

Use of a common signal wire for all controlled functions raises the possibility of an incorrect valve being

actuated. With the multiplexed electronic system, signals normally include “message security” coding to

minimize the chance of wrong commands being executed. These have historically been very successful

and no major operational problems have arisen due to incorrect commands.

As with direct wire systems, the presence of electrical power provides a convenient and economic means of

instrumenting the subsea system. This capability is becoming increasingly important as subsea systems

become more complex and regulatory bodies become more active.

A final aspect of the MUX E-H system of recent years is its associated compact topside support system.

This typically consists of hydraulic and electric power packs and a computer based master control station.

Interfaces to the subsea system consist of single or multiple junction boxes/or reels (depending on the

production facility type). The compact nature of all these components makes them ideal for restricted

space/weight applications which often arise in floating production application.

A typical MUX E-H,control system candidate would be:

Presence of electrical monitoring requirements

Large numbers of subsea valves requiring control

Short actuation time requirements

Deep water developments


Updated Dec. 1999

Multiple satellite completions

Extensive future expansion requirements

Surface facility weight and space limitations

3.6 Hybrid Systems

Hybrid systems are those which combine two or more of the previous systems types. This has frequently

been done in the past to provide a “back-up” system in the event of failure of the primary control system.

Typically, an E-H MUX system has had piggy-backed sequence or piloted hydraulic systems for use in the

event of electronic failure.

A second hybrid type has been the addition of a hard or multiplexed data acquisition system to one of the

hydraulic only systems. This can be an economic solution to the need for subsea data acquisition when the

expense of an E-H system cannot be justified and the parameters to be monitored are few.


Updated Dec. 1999

PIPELINES

TABLE OF CONTENTS

1.0 CATEGORIZATION OF PIPELINES........................................................................................ 1

1.1 Size, Length and Orientation .......................................................................... 1

1.2 Applications .................................................................................................. 1

1.3 Material ........................................................................................................ 1

2.0 DESIGN OF PIPELINES ........................................................................................................ 2

2.1 Inside Diameter ............................................................................................. 2

2.2 Wall Thickness ............................................................................................. 2

2.3 External Coatings .......................................................................................... 3

2.4 Hazard Protection.......................................................................................... 4

2.5 End Effects................................................................................................... 5

2.6 Corrosion Protection ...................................................................................... 5

3.0 INSTALLATION OF PIPELINES ............................................................................................ 7

3.1 ‘S’ Lay Methods ............................................................................................ 7

3.2 ‘J’ Lay Methods ............................................................................................. 9

3.3 Reel Methods................................................................................................ 9

3.4 Tow Methods ............................................................................................... 10

3.5 Pipeline Terminations.................................................................................... 11

3.6 Pipeline Burial.............................................................................................. 13

4.0 PIPELINE OPERATIONS...................................................................................................... 14

4.1 External Inspection....................................................................................... 14

4.2 Internal Inspection ........................................................................................ 14

4.3 Pipeline Repair............................................................................................. 14


Updated Dec. 1999

LIST OF FIGURES

FIGURE 1. Flexible Pipe

FIGURE 2. Hoop Stress Formula (Internal

Pressure)

FIGURE 3. Timoshenko Formula (External

Pressure)

FIGURE 4. Buckle Propagation

FIGURE 5. Buckle Arrestors

FIGURE 6. On-Bottom Stability

FIGURE 7. Pipeline Cross Sections

FIGURE 8. Trawl Damage to Pipelines

FIGURE 9. Pressure Compensated Safety Joint

with Check Valves

FIGURE 10. Axial Pipeline Expansion

FIGURE 11. Pipeline Expansion

FIGURE 12. Stinger Configurations

FIGURE 13. “S” Lay Ship

FIGURE 14. Semisubmersible Laybarge

SEMAC-1

FIGURE 15. Conventional Pipelay for 2300FSW

FIGURE 16. J-Curve Laying Method

FIGURE 17. “J” Lay Ship

FIGURE 18. Portable Reel Vessel

FIGURE 19. Apache Reel Ship

FIGURE 20. Tow-Out Techniques

FIGURE 21. Maximum Bollard Pull vs. Vessel

I.H.P.

FIGURE 22. Composite Flowline Bundle

FIGURE 23. Shore Approach and Crossing

Problems

FIGURE 24. Mid-Length Connection

FIGURE 25. J-Tube Pull-In

FIGURE 26. Flowline Bundle Away from Satellite

Well

FIGURE 27. Diverless Flowline & Umbilical

Connection System

FIGURE 28. Example of Sweep-in Technique

FIGURE 29. McPac Pull-In Tool

FIGURE 30. Surface/Near-Surface Tow Draw-

Down Technique

FIGURE 31. Fluidization Burial System

FIGURE 32. Trenching Techniques

FIGURE 33. Pipe Tracker Principle

FIGURE 34. “Smart” Pig

FIGURE 35. Diver Mechanical Repair Connectors


Updated Dec. 1999

1.0 CATEGORIZATION OF PIPELINES

1.1 Size, Length and Orientation

Pipelines are primarily horizontal tubulars used to transport a fluid. Typically, large diameter, long distance

and single phase product lines are called pipelines; smaller diameter, short distance, and, quite often,

multiphase product lines are called flowlines. They are functionally identical and are designed to the same

codes. In this section, the term pipeline will be used to refer to all line sizes; when the term flowline is

used, it will specify lines with 8-inch nominal diameter or smaller.

The term riser refers to primarily vertical tubulars that transport fluids from the seafloor to a surface facility.

Though functionally identical to pipelines, risers are typically designed to more stringent codes (e.g. larger

satiety factors) because of a higher potential of damage due to increased local activity, and because of their

proximity to humans. Also, short lengths of pipeline immediately adjacent to a surface facility are some

times designed to riser codes for the same reasons.

1.2 Applications

Pipelines have different designations depending on their application. An export pipeline transports a fluid

product from an offshore surface facility to an onshore location. A particularly large diameter export pipeline

that transports a like product from multiple offshore facilities is typically called a trunkline. Product lines

connecting offshore facilities are typically called intra or interfield pipelines depending on whether the

facilities are in the same field or not. Collectively, a system at such lines can be called a gathering system.

Product lines going to an offshore loading terminal are called offloading or offtaking pipelines depending on

whether the product is being exported or imported from the loading terminal. Similar names can be applied

to other special application pipelines (e.g. lines to a flare tower); the thing to remember is that they are

functionally the same.

1.3 Material

Most offshore pipelines are constructed of carbon steel. The steel is available in a range of grades (i.e.,

yield strengths), and in discrete sizes, (i.e. established combinations of outside and inside diameters)

information on line pipe can be found in API 5.L “Specification For Line Pipe.” Pipelines can also be flexible

pipe as shown in Figure 1. A flexible pipe is an armored hose that can withstand external hydrostatic

pressure. A spiral wound, interlocking, steel channel with a “Z” cross-section (called “Z” lock) provides the

resistance to hydrostatic collapse. Spiral wound flat wire provides axial tension capacity. The layers of

steel windings are typically separated by layers of extruded synthetic material. The outer layer is also

normally an extruded synthetic material, typically a nylon derivative . This outer synthetic layer is the


Updated Dec. 1999

primary contributor to bending stiffness (i.e. the area moment of inertia is effectively confined to the outer

extruded layer). The combination of layers can be constructed to meet the users need for axial strength,

burst/collapse resistance, product chemistry, and even thermal conductivity.


Updated Dec. 1999

2.0 DESIGN OF PIPELINES

The following section relates to the design of steel pipelines. Specific reference will be made when

discussing flexible pipelines.

2.1 Inside Diameter

The inside diameter (ID) of a pipeline is controlled by through-put considerations. The through-put analysis

typically considers flowing wellhead pressure and temperature, ambient temperature, required receiving

pressure, fluid composition and route description (i.e., length, elevation, profile, etc.). The analysis usually

involves multiphase conditions, a subject that is discussed in a latter Section.

2.2 Wall Thickness

For a given ID, the wall thickness (WT) is a function of internal operating and external ambient pressures.

The internal pressure calculation uses a hoop stress (i.e. circumferential stress) formula that is shown in

Figure 2. As shown, the input variables and definitions change slightly with the different design codes (e.g.

DnV, API).

External pressure must be accounted for in two ways:

Hydrostatic collapse (Buckling)

Buckle propagation

The principle formula for calculating the external hydrostatic collapse pressure was developed by

Timoshenko, and presented in Figure 3. In its unaltered form, this formula chooses the lower of the external

pressures required to either 1) yield the pipe wall in compression (i.e., a compression hoop stress); or 2)

cause elastic instability in a circular cross section with an initial out-of-roundness (i.e., pipe ovality). A

manufacturing tolerance of 2% is typically used for initial out-of-roundness; this means that the maximum

difference of any two measurements of pipe outside diameter can be only 2% of the average outside

diameter. Various design codes and company design practices apply a range of safety factors to the

calculated Timoshenko pressure to account for all other uncertainties.

Once a pipeline has buckled due to hydrostatic pressure, the pipe will continue to collapse along the length

of the pipeline in both directions until the ambient external pressure is below a critical buckle propagation

pressure. This critical propagation pressure, as calculated in Figure 4, is lower than the pressure required

to cause initial hydrostatic collapse. Any buckle has the potential of causing a crack in the pipe wall and

flooding the pipeline. This is called a wet buckle, and could have disastrous consequences if it occurs

during installation when submerged pipe weight is critical.


Updated Dec. 1999

Two design approaches are available to deal with buckle propagation. The pipe wall thickness can either be

designed to withstand buckle propagation along its length, or a series of buckle arresters can be

constructed into the pipeline that prevent the buckle for propagating further. Short, small diameter flowlines

usually increase wall thickness to resist propagation while long, large diameter pipelines usually use

arresters.

There are several types of arresters. The simplest is a thick section of pipe welded into the pipeline. Other

arresters are bolted on collars or a spiral wound bar. Figure 5 shows some of the typical arresters used.

After a WT is calculated for a specified internal and external operating pressure, an allowance is usually

added for corrosion and negative manufacturing tolerance. The DnV code specifies 2mm (.0787 in) for

corrosion while API recommends consideration of an allowance but does not give specific value. In the

U.S., a corrosion allowance of .0625 in is typically used. Both DnV and API recommend a 12.5% negative

manufacturer’s tolerance.

2.3 External Coatings

There are three typical external coatings applied to a pipeline: sealant for corrosion protection; reinforced

concrete for added weight; and insulation for prevention of heat loss.

The most frequently used corrosion coatings are: Asphalt Enamel; Bitumen; Coal Tar Epoxy; and Film

Bonded Epoxy (FBE). The corrosion coat is applied directly to the pipe. FBE is the most resistant to

damage but also the most expensive due to surface preparation. Asphalt Enamel, or Coal Tar Epoxy are

more often used underneath a protective concrete coating.

Pipelines are typically laid empty and must remain stable on the seafloor after installation. Even if the line

is intended to carry a liquid, the empty pipeline must remain stable on-bottom in the expected worst

seasonal storm.

On bottom stability requires that a pipeline not lateral move under the action of the design wave and bottom

current. Figure 6 presents the modified version of the Morrison Equation used to calculate on-bottom

stability. The pipe can be acted upon by three hydrodynamic forces: a lateral drag (CD term) and inertial

force (CM term); and a vertical lift force (CL term). The lift force counteracts the submerged pipe weight.

The lateral resistance force is the product of the net vertical downward force and soil friction (µ term).

Many oil companies have derived their own values for CD, CL, CM, and µ from experimental programs.

Figure 6 presents the values recommended by DnV. Also shown are the typical values used by industry in

the Gulf of Mexico.

There are two ways to add weight to a pipeline: increase the wall thickness or apply a concrete weight

coating. If the weight need is slight, a lower grade material could be considered which would increase the


Updated Dec. 1999

required wall thickness and hence increase submerged pipe weight. In general, increasing steel weight is

more expensive then adding a concrete coating.

The concrete can be either high density (190 lb./ft3) or low density (140 lb./ft3). The higher density material

is more expensive but has better impact resistance for damage protection (discussed later). Most oil

companies specify the higher density.

The concrete is reinforced with a steel wire mesh or a steel wire cage, the cage providing greater structural

integrity. The concrete is usually applied rotating the pipe with reinforcing wire around its axis while the

concrete is in blown into the reinforcing wire.

Thermal insulation is added as an outer coating when heat loss is critical. Some reasons for retarding heat

loss are: protection of perma-frost soils, improve viscosity of low API gravity crudes, or suppress hydrate

formation. Three common types of insulating materials are rubbers (e.g. neoprene), plastics (e.g.

polyethylene) and foams (e.g. polyurethane). Polyethylene has about half the thermal conductivity of

neoprene (i.e. twice as good an insulator); polyurethane foam has half again the thermal conductivity of

polyethylene. Polyurethane foam, cannot resist hydrostatic pressure and requires an external pressure

barrier. In shallow water, a polyethylene jacket can be used. Beyond around 100 ft. water depth, a steel

carrier pipe is typically used creating a pipe-in-a-pipe construction.

Figure 7 shows two pipeline cross sections. In Figure 7A, a simple concrete coat is applied over a coat for

epoxy (somatic) corrosion coat. Figure 7B combines several features for a shallow pipeline with a weight

coat over a polyurethane insulation layer encapsulated within a polyethylene jacket.

2.4 Hazard Protection

There are two sources of hazards: natural and manmade. Proper on-bottom stability design will prevent

storm damage. Bottom instability due to geotechnical hazards is another natural problem, more prevalent in

certain areas. For example, small methane gas pockets just below the bottom surface cause collapse of

the seafloor. Also, soft clay and silt material on steep slopes may be prone to mud slides. A route survey

using imaging sonars (e.g., sidescan sonars) will show small scale seafloor relief: a sub-bottom profiler will

show the stratification of the near bottom sediments. Both survey tools can alleviate many geotechnical

problems by allowing the designer to avoid general regions of detectable instabilities. Some geotechnical

problems can not be avoided such as crossing a steep upslope gradient; keeping the pipeline perpendicular

to the bathymetry allows potential mud slides to flow along the pipeline, and not drag pipeline down slope

causing excessive stressing.

Manmade hazards are more difficult to guard against. The possibility of dropped objects increases around a

surface facility. Covering pipelines with mats or dumped rock around platforms protects the pipeline but

makes inspection/repair more difficult. Choosing a route into the platform that avoids going under the lifting


Updated Dec. 1999

range of surface cranes can reduce the likelihood of dropped objects and eliminate the regulatory need for

additional coverings (e.g. come in under a flare boom).

Dragged anchors are a problem. There is no effective way of protecting a pipeline from the dragged anchor

of a construction or drilling vessel because of their weight and depth of penetration. The best way to

alleviate the problem is by carefully monitoring pipeline and anchor positions.

In shipping lanes, or areas prone to random anchoring by commercial vessels, pipelines must be buried (i.e.

trenched and backfilled) below the bottom 3-ft. or more depending on regulatory requirements. In the U.S.,

the 3-ft. depth requirement goes back to the depth land pipelines had to be buried to avoid farm plows.

Certain countries require rock dumping to protect against anchorage damage.

Fishing equipment also collides with pipelines. In many areas of the world, fishermen pull trawl nets along

the bottom using trawl boards to keep the nets open. Figure 8 depicts a typical scenario were a trawl net is

dragged over the pipeline. Pipelines less than 6-inch diameter are prone to snagging by trawl boards; trawl

boards tend to go over pipelines 8-inches in diameter and greater.

Burying the pipeline in fishing areas is usually required. Trenching a pipeline below the bottom, but not

backfilling it, actually creates a worse situation where the trawl board actually can drop onto the pipeline.

Coating the pipeline with high density concrete in sufficient thickness (1-inch or more) has been shown to

absorb the impact of even the heaviest trawl boards. Typically if an operator can convince the local fishing

community that their concrete coated pipeline will damage neither the fishermen’s nets nor their pipeline,

the appropriate regulatory bodies will give a variance on burying the line.

In order to safeguard against damaging platforms or subsea templates, many operators require a weak link,

or breakaway joint, be located near the pipeline tie-in point. Figure 9 shows a typical safety joint that acts

as a weak link that will separate under a predetermined axial tension while still maintaining design operating

requirements. The safety joint shown also has pressure activated check valves in order to isolate the

separation.

2.5 End Effects

Pipelines experience two loading conditions that effect the area of their termination: thermal strain and the

“end cap” effect. A thermal compressive strain is created when a material is heated while being axially

constrained; the pipe would relieve the strain with expansion wherever it was unconstrained. The end cap

effect arises from the internal pressure acting on a net projected forward area, and is present whenever a

pipeline takes a bend. For straight pipe, there is no net forward projected area; with a right angle bend, the

cross section of the pipe becomes the net forward projected area.

Typically these two effects happen concurrently as shown in Figure 10. The chart shown is for a 24-inch

buried pipeline coming into a vertical riser. The elongation shown was the product of the combined effects.


Updated Dec. 1999

Figure 11 shows the expression for axial force created by the two effects.

Any constrained termination must be designed to resist the combined load. Even if the termination resists

movement, thermal expansion will probably cause some section of the pipeline to expand; the actual

amount of elongation becomes a function of the length of pipeline free to expand. It is prudent design to

consider any pipeline length laid straight on the seafloor to try to expand in-line, usually towards the hotter

end. This is why dog leg bends are laid into the line as it approaches a termination point. Also, expansion

spools are placed just outboard of a termination.

Because break-away soil friction is greater than sliding friction, the pipeline will not return to its original

position when cooled (i.e. hysteresis). This propensity for the pipeline to ratchet across the seafloor must

be taken into consideration when designing a pipeline tie-in.

2.6 Corrosion Protection

The external corrosion coating discussed earlier is typically considered to be damaged over the life of the

pipeline, thus exposing bare pipe to oxidation ( i.e., corrosion). Electrons would be stripped from the stable

iron atom by the positive hydrogen ion to form free hydrogen gas leaving the iron to combine with the oxygen

ion to form iron oxide, or rust.

The way to avoid iron oxidation is to provide a supply of available electrons. The electrons can be supplied

by an impressed current or from sacrificial anodes (i.e., cathodic protection). Pipelines and risers typically

use anodes made of zinc or aluminum alloys. Risers are sometimes protected by impressed currents.

The anodes are sized to provide a minimum current to cover an area expected to be exposed over the life of

the pipeline. Typical minimum values are a 5 ma current over 10% of the pipeline surface over a 20 year

period. The anodes must be exposed to the seawater (i.e. not covered by any coatings), and electrically

attached to the pipe.


Updated Dec. 1999

3.0 INSTALLATION OF PIPELINES

The following section refers to the design of steel pipelines. Specific mention will be made when referring to

flexible pipelines.

3.1 ‘S’ Lay Methods

The most common way to install pipelines is to transport individual lengths of pipeline, called joints, to a

moored lay vessel that continuously welds the lengths together, laying them off the stern of the vessel as it

slowly pulls itself forward on its mooring. The welding is done at series of weld stations laid out on the

vessel’s deck in a straight line called the firing line. The joints are usually 40 ft. long, the same length in

which they were rolled, or extruded, at the pipe mill.

A new pipe joint is positioned at the start of the firing line where the ends are prepared for welding. The joint

is aligned to the previous joint, usually with an internal alignment clamp. The initial circumferential weld is a

full penetration weld called the root pass. Additional passes made at subsequent stations along the firing

line fill in the beveled profile gap between the two pipe joints. The final pass is the cap weld, and may or

may not be ground flush with the pipe surface.

At a station near the end of the firing line, an X ray is taken of the weld in order to detect cracks. If cracks

of an unacceptable length are detected, the region of the weld with the crack must be ground out, new weld

material inserted, and the entire weld reexamined. Needless to say, in-line repairs are very expensive and

warrant the use of highly qualified welders using proven methods and equipment. There are society codes

for qualifying welders, materials and methods; some clients have their own standards.

The last station on the firing line is where the external corrosion coating is applied to the welded area. If

concrete coating is used, a quick set material is cast in forms positioned around the weld area in order to

provide a continuous outside surface.

Along the firing line are tensioners. These are hydraulically driven devices that grip the pipe with long rubber

tractor treads. The purpose of a tensioner is maintain a minimum tension on the pipeline. If the tension

goes below the threshold, the tensioner draws the pipeline back onto the barge until the threshold is

achieved. If the tension exceeds the threshold, the tensioner pays out the pipeline from the barge until the

tension decreases to the threshold. In order to prevent the tensioner from continuously drawing in and

paying out the pipeline, a distraction to the welders, a deadband is set between the upper and lower tension

thresholds.

The rate at which the pipeline can be constructed, the lay rate, is usually a function of how fast the

preceding steps can be done. A rate of 2 miles/day is considered fast, with 1 mile/day more typical. As a

way of speeding up the process, some lay vessels can handle 80 ft. double joints where two 40 ft. joints are


Updated Dec. 1999

welded together on the barge or onshore. Theoretically, the lay rate is either determined by the time it takes

to fill the gap with weld material (i.e., number of weld stations and the rate of depositing weld material) or the

time it takes to perform the X ray. In deep water, the rate at which the lay vessel can advance, or move-up,

on its mooring lines could control the lay rate.

After the pipeline leaves the firing line, the curvature must be controlled as it descends by use of a stinger.

Figure 12 shows the three types of stinger. In very shallow water, the stinger can be essentially straight and

extend to near the bottom (Figure 12A).

As the water depth increases, the pipeline is allowed to assume a double reverse bend configuration as

shown in Figure 12B. In this position, the upper bend, or overbend, must be supported by a curved stinger.

An articulated stinger, as shown in Figure 12B, is a series of straight pontoon sections hinged together. By

matching pontoon buoyancy and tension, the articulated segments can be made to create the appropriate

overbend curvature. An alternative stinger design is a continuous curved stinger as shown in Figure 12C.

The curved stinger can be rigidly fixed to the lay vessel, or it can be hinged. Continuous curved stingers can

be constructed as wide truss frames to resist lateral deflection. Articulated stingers are more easily

adjusted to meet the design needs of water depth and pipe size.

The lower bend, or sagbend, begins with the point of bend reversal (i.e., the point of inflection) which is near

the point of departure from the stinger, and extends a little beyond the point of touchdown on the seafloor.

The sagbend curvature is controlled by the tension in the pipeline.

The early lay vessels were flat bottom barges; this is still the most common type. Figure 13 is ship shape

“ALLSEAS” that can operate with a traditional spread moored pattern, or by dynamic positioning (DP) with

thrusters, or a combination of the two. The ship shape has advantages of faster mobilization; the DP allows

it to maneuver in confined areas such as is likely near existing platforms.

Figure 14 shows one of the large semisubmersible lay vessel “SEMAC” that is sometimes referred to as a

third generation vessel. Note the wide truss stinger for rough weather operation. A lay vessel must follow a

predetermined path, regardless of weather. The semisubmersible design has a low response to the sea

from all directions, unlike a monohull vessel.

Lay vessels using the ‘S’ lay method face problems in laying pipe in deep water. The problems can be seen

in Figure 15. Shown is a plot of departure angle from the stinger versus laybarge tension for a 10 inch

pipeline in 2300 ft. water depth. The graph shows that the lay vessel must have at least 320,000lb. tension

to lay with a departure angle less than 45°. Nominal departure angles for conventional barges are 30°and

less. Only a few vessels have over 320,000lb. tension. Stingers can be lengthened to accommodate 45° to

60° departure angles which brings tension requirements back into the range of more vessels. Beyond 60°

departure angle, small tension variations can result in larger changes in departure angle. This makes the

setting of the deadband range on the tensioners very critical; too large a deadband and the pipe could


Updated Dec. 1999

buckle over the tip of the stinger with a small amount of vessel surge movement. At the same time, the

mooring becomes softer in deep water causing longer surge amplitudes.

Pipelines can be laid by the ‘S’ lay method in deep water. However, the problems involved make it

achievable by only a very few vessels after significant modifications. For these reasons, other methods have

been sought that reduce the tensioning, stinger and mooring problems of the ‘S’ lay. One such method is

the ‘J’ lay.

3.2 ‘J’ Lay Methods

‘J’ lay methods substantially eliminate the overbend by effectively allowing the pipe to depart from the firing

line at the point of inflection. Referring back to the curve in Figure 15, the required tension drops

dramatically when the departure angle is 60° or higher.

Such a high firing line angle, or ramp angle as it is known, requires single station welding. In single station

welding, the pipe joint is aligned, welded from root pass to cap weld, X rayed and field wrapped all at the

same near vertical station.

A great deal of research has gone into finding a fast method for welding pipe at a single station in order to

have lay rates comparable to the ‘S’ lay methods. Laser and electron beam welding, friction welding, and

flash butt welding are a few of these methods. The only methods recognized to give a metallurgically

acceptable weld are still the same conventional methods used in ‘S’ lay methods.

One way of improving lay rate is to use triple joints, or 120 ft. joints. The problem of handling such a joint in

heavy seas is not trivial.

Several vessel types have been considered for use with a ‘J’ lay system. Figure 16 shows the concept of

using a ship shaped drilling rig. In order to maintain the sagbend, there must be an adequate pipe tension

at the touchdown point. This requires a lateral component in the pipe tension at the vessel. Either the

single station is maintained at an angle or a small vertical stinger is needed to impart the required later

component. The latter is assumed in Figure 16.

Figure 17 shows the same ‘S’ lay vessel from Figure 13 now configured for the ‘J’ lay. This design

incorporates a stalking system capable of handling triple joints. In the ‘J’ lay mode, the vessel would

operate exclusively on DP. The ramp is hinged so that the angle of departure can be adjusted during the

laying operation, which it must do in order to adjust for water depth. The vessel is shown laying backwards

so that the vessel can back into a surface facility and directly transfer the end of the pipeline.

3.3 Reel Methods

Pipelines have been installed using reels for as long as pipeline have been laid offshore. In the reel method,


Updated Dec. 1999

rigid pipelines are bent beyond their elastic limit when coiled on the reels. When they are unreeled offshore,

they must be run through straightening rolls. Lay rates of 1 to 2 miles/hour are typical with reel methods.

In order to resist buckling, reeled pipes generally have a diameter to wall thickness ratio of less than 25.

The yield strength of the pipe material is generally 60,000 psi or less in order to allow plastic deformation

without excessive forces in the straightening rollers.

The reels can be horizontal or vertical, and built into the vessel or portable. The forces required to straighten

the pipe limits the size of pipe that can be installed by reel methods. The weight of the pipe generally limits

the length (i.e., the bearing limitation) though volume sometimes is a limit.

Horizontal reel vessels have the advantage of pipe storage due to the high load capacity of its lazy susan

type bearing. However, they must use a ‘S’ lay method for supporting the freespan since the pipe comes off

the reel horizontally. Vertical reel vessels have the advantage of ‘J’ lay since a high departure angle can be

used.

Concrete coated pipe can not be installed by reel methods. Likewise, anodes, insulation and other external

systems must be attached after the pipe has been straightened. Also remember that all unreeled pipe will

have some residual curvature; the straightening process is not perfect.

Figure 18 shows a portable reel mounted on the fantail of an ocean going tug. Portable reels are popular for

small size pipe (i.e., 4 inch diameter or less). They are used when laying multiple pipelines in a single

pass; for example installing a 4 inch line along side a larger sized line being constructed on the vessel.

Figure 19 shows the “APACHE” reel ship. It can lay up to 16 inch pipe with 280,000lb. tension capacity.

The high departure angle capability and DP stationkeeping make it suitably for deep water

3.4 Tow Methods

With tow methods, either single or multiple lines (i.e., line bundles) are made up onshore, or near shore in

shallow water, and towed out to an offshore site, positioned between the two terminations, and connected.

The towed pipeline system can be on the surface, tethered below the surface, hung at mid-depth, or on/near

the bottom.

Figure 20 shows the various tow-out techniques. Surface tows use simple floatation systems, offer the least

towing resistance, and require the least route survey; however, they are the most prone to weather and

surface collision. The near surface methods reduce these disadvantages at the expense of complicating the

floatation system and increasing the tow resistance. On bottom systems (not shown in Figure 20) eliminate

the floatation system but cause the highest tow resistance, and pose the greatest danger with on bottom

collisions that require the most extensive route survey. Near bottom methods reduce these disadvantages

at the expense of complicating the floatation system. Mid-depth tows offer the advantages of surface tows


Updated Dec. 1999

with none of its disadvantages; however the method is limited in application by the catenary equation

relationship between pipeline length and weight, water depth, and

pull force, both fore and aft.

The ocean going tug is the principle offshore equipment used. The various towing techniques require

different horizontal, or bollard, pull loads from the tug. The surface and near surface techniques require the

least bollard pull per length of line. The mid-depth tow must have sufficient pull from the leading and trailing

tugs to keep the pipeline from sagging in the middle and dragging on bottom. The on/near tow methods

must overcome soil friction. Figure 21 shows the relationship between bollard pull and tug horsepower for

typical ocean going tugs. Towing speeds can range from 6 knots for surface tow down to 1 to 2 knots for on

bottom tows.

A principle attraction of tow methods is that multipipeline/umbilical systems can be fabricated and tested on

shore, and encased in a carrier pipe. Figure 22 shows the cross section of a possible bundle design. Use

of a carrier pipe has several advantages: hazard protection, buoyancy, and thermal insulation. The

disadvantage is the added expense.

Manifold assemblies have been built into towed system for tieing satellite trees or other pipelines. Again,

the advantage is land testing the system in conjunction with its pipeline/ umbilicals. Also, the cost of a

separate installation spread is avoided.

3.5 Pipeline Terminations

A pipeline termination can either be a first end or a second end termination. In a first end termination, the

pipe is either drawn off a stationary lay vessel, or the lay vessel pulls against a stationary anchor point

called a deadman with a steel cable attached to a bull nose at the end of the pipe. In a second end

termination, the pipe is laid off the lay vessel with use of steel cable called an abandonment line. It is

attached to a bull nose at the end of the pipe, and run to the abandonment and recovery (A&R) winch on the

vessel. As the name implies, the A&R winch is also used to recover an abandoned pipeline from the

seafloor.

The most familiar first end pipeline termination is a shore crossing. Figure 23 shows the typical obstacles

faced in shore crossings. Shore line obstacles are typically avoided when possible. When not possible, a

tunnel is sometimes dug or drilled under the obstacles. The surf zone poses the problem of both seasonal

and long term erosion/deposition. Typically a trench lined on both sides with cofferdams is dug deep

enough to avoid the worse case erosion. Ice pack erosion and iceberg scour pose additional problems in

particular areas. Again the long term extent of the problem must be assessed so that the line can be

placed deep enough, either with trenches, or tunnels. Ice prone areas may also pose the additional problem

of permafrost in which case the line must be insulated as to avoid melting the permafrost and possibly


Updated Dec. 1999

causing a line break.

For long pipelines, one vessel is sometimes used to lay the offshore portion while a second vessel is used

to install the shore crossing. is such cases, the two lines are tied together with a mid-length connection is

shallow water. The steps in such a connection are shown in Figure 24. The lines are laid parallel to other

with sufficient excess line os that a single vessel can lift both lines to the surface along its side. A series of

small cranes called davits are typically used to the lift the lines, possibly with the aid of floatation on the

lines. After the two lines a cut and welded together, the vertical loop is laid over on its side by moving the

vessel to beam as the line is lowered.

A J-tube pull-in at a platform is a familiar fist end termination. An oversized riser pipe is installed in the

platform at the time of its fabrication. At the seafloor end, the riser has a right angle bend. At the time of

pipeline installation, a cable is run through the J-tube and out to the stationary lay vessel. As in a shore

crossing, winches draw the pipeline off the lay vessel, and into the J-tube. As shown in Figure 25, the

pipeline is plastically deformed as it passes through the right angle bend section in the J-tube on its way to

the surface. Special computer programs, supported by extensive test results, are used to predict the pipe

stresses and pull loads involved. As with reel installation methods, pipe used in J-tubes should have a

diameter to wall thickness ratio of 25 or less.

A J-tube pull-in can also be used as a second end termination. The pipeline is laid past the platform. A

pull-in cable is run through the J-tube to the bull nose at the end of the pipeline, and pulled towards the J-

tube sweeping the pipeline across the bottom. With sufficient excess pipe having been laid on bottom, the

pipeline is pulled through the J-tube to the surface.

A reverse J-tube method has also been used as a first end termination. In this method, the pipe is vertically

stalked and welded together on the platform, and lowered down through the J-tube. The weight of the pipe is

sufficient to force the pipe through the right angle bend shoe and the reverse bend section at the outboard

end of the tube near the seafloor. A recovery cable is run from the lay vessel A&R winch to the pipeline. As

new joints are stalked on the platform, the lay vessel takes in the recovery line, ultimately bringing the

pipeline onboard.

A first end termination to a seafloor structure (e.g., subsea tree) usually involves some type of lay-away

method. Figure 26 shows a typical lay-away sequence.

A cable from the first end pulling head is transferred to a vessel overhead the pipeline termination port. A

sheave is lowered down to the termination port with the pull cable. The pull cable is drawn in as the lay

vessel pays out the pipeline until it arrives at the termination port.

Divers remove the pulling head and make a flanged connection. In deep water, too much effective elasticity

in the pulling cable may require the pulling device to be located on the seafloor, rather than on the overhead

vessel. Also in deep water, other means besides divers must be used to make the connection. Various


Updated Dec. 1999

suppliers have developed remote hydraulic pipeline connection tools such as the one shown in Figure 27.

These devices can make-up a mechanical connection with metal-to-metal seals once the pipeline ends have

been properly aligned and positioned.

First end terminations, whether to platforms or to subsea structures, have the advantage of positioning and

aligning the pipeline end before the remaining pipeline is installed on the seafloor. Second end terminations

have neither of these advantages since the pipeline exists on the seafloor making any adjustment to the

position or alignment of the pipeline end very difficult.

To understand second end connections, a clear distinction must be made between positioning, aligning, and

connecting. Portioning brings the pipeline end to the proper coordinates; aligning puts the pipeline in proper

register with the inboard piping; and connecting mechanically seals the pipeline end to the inboard piping.

Various methods may combine two of these steps but no method does all three simultaneously.

Figure 28 shows the sweep-in method, variations of which are known as the bend-around or bend-and-deflect

methods. In these methods the second end of the pipeline is lowered into a target area. The end is pulled

towards the pipeline port. In Figure 28 multiple lines are used to deflect the pipeline; this allows the end of

the pipeline to be both positioned and aligned at the same time. A variation of this approach uses a single

pull-in line between the pipeline end and the termination port; in that case, a special tool located at the

termination port must align the pipeline end after it has been positioned by the pull-in cable. Figure 29

shows one such alignment tool. Because of the moments generated in order to align the pipeline, these

tools are usually massive; the one shown weighs 55,000lb. in air. A tool similar to that shown in Figure 26

can then make the mechanical connection between the pipeline and the inboard piping.

The sweep-in technique is typically used with both ends of a near-bottom, on-bottom or mid-depth tow

method. In such a case, the entire towed pipeline is positioned in a target area prior to making the final

bend-around.

For near-surface and on-surface tow methods a draw-down technique is typically used. Figure 30 shows the

typical sequence of a draw-down technique. Note that the excess length is adjusted for with a bend in the

vertical plane due to buoys, rather than a bend in the lateral plane as in the sweep-in technique.

3.6 Pipeline Burial

Burial constitutes the acts of trenching and backfilling. Some methods accomplish both processes in a

single operation. The type of method is usually dictated by the type of soil in the seabed.

Figure 31 shows a typical jet sled in operation. High pressure pumps on the burial vessel drive water

through the nozzles located in the trailing sled. The jetting water fluidizes the seabed, effectively reducing

the bearing capacity of the soil beneath the pipeline allowing it to sink to its prescribed depth. The sled

uses the pipeline as a guide as the surface advances.


Updated Dec. 1999

The fluidized soil eventually resettles, though much of the seabed material will be transported by the water

jet currents away from the pipeline. The jet sled can be used in consolidated soils in which the jets can cut

a steep walled trench as shown in Figure 31. In unconsolidated materials like sand, a jet sled system will

just blow a shallow trench requiring repeated passes to get the pipeline down to the prescribed depth.

Figure 32 shows a plow system in operation. The seafloor plow cuts a wide trench with stable slopes, even

for unconsolidated materials. The pipeline acts as the guide as the plow is pulled by a surface vessel. The

plow in turn guides the pipeline down into the trench as the plow is pulled ahead. The trench will backfill

naturally with soil movement on the seafloor, or it can be actively backfilled.

Mechanical trenchers have been used that cut a trench beneath a pipeline with a combination rotating

cutters and suction pumps to remove the spoils. All burial systems, particularly the mechanical systems

suffer when soil types change along the route, or boulders are encountered.


Updated Dec. 1999

4.0 PIPELINE OPERATIONS

If properly designed, pipelines would have a low operating cost. Most maintenance is routine scheduled

inspections, both inside and outside. Pipeline breaks are more often the result of man rather than natural

(e.g., anchor snag).

4.1 External Inspection

Depending on local regulations, pipelines are routinely inspected to confirm location, look for external

damage, and/or check the adequacy of the cathodic protection. Pipelines are also inspected in case of

damage to locate the break and access the damage. In shallow water, pipelines can be “walked” by divers,

though crawling and feeling would be a better description. ROVs “flying” the pipeline have replaced divers in

many inspection applications, especially in those areas which do not allow “live boating” with divers.

When pipelines are buried and covered, magnetometer type devices are used to detect and follow the

pipeline. Figure 33 shows the principle of the magnetometer where a the presence of a massive electrically

conducting object like a pipeline causes a measurable disturbance in the magnet field of the instrument.

The instrument can be towed near bottom, or made into an ROV workpackage.

4.2 Internal Inspection

Routine purging of pipelines are done with plug like devices called pigs. The pig conforms to the walls of the

pipe, sweeping all that is in front of it such as water trapped in low sections, wax built-up on the walls, etc.

Such pigs are passive devices and do not measure wall thicknesses in order to detect corrosion.

Caliper pigs are mechanical devices that, as implied in their name, use caliper fingers, spring loaded to

remain in contact with the wall, to measure inside diameter and mechanically record it on a chart log.

Caliper pigs do not measure wall thickness, nor do can they detect pitting is the pipe wall.

“Smart” pigs are electronic devices that use magnetic fields to detect variations in the amount of metal in the

pipe wall caused by uniform corrosion and/or pitting. Figure 34 shows a typical “smart” pig. The pig has

electric power, magnetic transducers, odometer, electronic instrumentation, and fluid power cups, all of

which are packaged in a multi-segmented system. Use of “smart” pigs typically requires a minimum pipe

bend radius of five times the pipe diameter.

4.3 Pipeline Repair

A pipeline repair operation consists of locating the break, cutting out the broken section, removing it, fitting

the two pipe ends to receive a spool, measuring the required spool, fabricating the spool, positioning the

spool, and making both end connections on the spool. Figure 35 shows the basic components of any


Updated Dec. 1999

repair. In the first case a spool is used. In the second case, the two end fittings serve the role of the spool.

The system shown in Figure 35 requires the use of divers. In water depths beyond diver capability, special

tool systems have been developed to essentially replace the diver (e.g., ROV workpackages, submersible

systems, drill pipe running tools, etc.). The steps required for a repair, however, remain the same.


Updated Dec. 1999

FLUID PROPERTIES AND PRODUCTION

TABLE OF CONTENTS

1.0 INTRODUCTION ................................................................................................................... 1

2.0 HYDROCARBON PHASE BEHAVIOR..................................................................................... 2

2.1 Composition/Classification of Petroleum .......................................................... 2

2.1.1 Open or Straight-Chain Compounds (Alkanes) .................................................... 2

2.1.2 Closed-Chain or Ring Compounds (Cycloalkanes)............................................... 2

2.1.3 Isomers ........................................................................................................... 2

2.2 Phase Diagrams............................................................................................ 3

2.2.1 Single Component System................................................................................ 3

2.2.2 Multi-Component System.................................................................................. 4

2.3 Flash Vaporization Equation........................................................................... 5

2.3.1 Stage Separation..................................................................................... 6

2.3.2 Reservoir Studies .................................................................................... 6

2.3.3 Miscellaneous Applications ...................................................................... 7

2.4 Stage Separation of Oil and Gas ..................................................................... 7

2.5 Fluid Properties ............................................................................................. 7

3.0 FLUID FLOW IN PIPING...................................................................................................... 10

3.1 Fluid Flow Theory ......................................................................................... 10

3.2 Single Phase Flow........................................................................................ 11

3.2.1 Flow of Liquids ....................................................................................... 11

3.2.2 Flow of Gases ........................................................................................ 12

3.3 Two Phase Flow........................................................................................... 14

3.3.1 Two-Phase Flow Regimes ....................................................................... 15

3.3.2 Pressure Drop Predictions....................................................................... 15

4.0 OPERATIONAL CONSIDERATIONS ..................................................................................... 17

4.1 Single Versus Two-Phase Lines..................................................................... 17

4.2 Natural Gas Hydrates ................................................................................... 18

4.3 Paraffin........................................................................................................ 20

4.4 Sand Protection ........................................................................................... 21


Updated Dec. 1999

LIST OF FIGURES

FIGURE 1. Pressure-Temperature Diagram for a Pure Component

FIGURE 2. Pressure-Temperature Diagram for a Binary System

FIGURE 3. Examples of Retrograde Behavior

FIGURE 4. Phase Diagrams for Typical Reservoir Fluids

FIGURE 5. Flow Diagram for Two-Stage Separation

FIGURE 6. Viscosity as a Function of Temperature

FIGURE 7. Moody Friction Factor as a Function of Reynolds Number and Relative Roughness

FIGURE 8. Relative Roughness as a Function of Pipe Diameter and Material

FIGURE 9. Resistance of Valves and Fittings

FIGURE 10. Resistance of Valves and Fittings

FIGURE 11. Two-Phase Flow Patterns in Horizontal Flow

FIGURE 12. Two-Phase Flow Pattern Regions in Horizontal Flow

FIGURE 13. Conditions for Hydrate Formation of Natural Gas

FIGURE 14. Freezing Points of Aqueous Glycol Solutions

FIGURE 15. Viscosities of Aqueous Ethylene Glycol Solutions and Methanol


Updated Dec. 1999

1.0 INTRODUCTION

The subject matter covered in this lecture is divided into three areas: hydrocarbon phase behavior, fluid flow

in piping, and operational considerations. These areas serve to describe the behavior of produced reservoir

fluids an dhow this behavior impacts the production system from the reservoir to the initial separation

facilities. A detailed discussion of well operations and production facilities will be covered in later lectures.

Knowledge of the vapor-liquid phase behavior of hydrocarbon reserves to be produced is essential for proper

design of the production system. Whether the fluid is all vapor, all liquid, or both can have a major impact

on reservoir performance and thus ultimate recovery, and the design of piping systems. Many times the

phase behavior can be controlled to the advantage of the operator, e.g., maintaining single phase production

to minimize pressure loss in long flowlines. The behavior and characteristics of the produced hydrocarbons

is always a critical factor in the design of separation, process, and pumping equipment.


Updated Dec. 1999

2.0 HYDROCARBON PHASE BEHAVIOR

2.1 Composition/Classification of Petroleum

Petroleum is a complex mixture of naturally occurring compounds. These compounds are principally

hydrocarbons (carbon-hydrogen molecules) and range from methane to asphalt. Ultimate analyses of

petroleum, however, may indicate the presence of small amounts of nitrogen, oxygen, and sulfur

compounds. There are no fixed rules on the distribution of hydrocarbons in reservoirs. However, in moving

from crude oil reservoirs to volatile oil to gas condensate reservoirs, the amount of simple, low molecular

weight constituents increases.

Hydrocarbons are classified as open-chain and closed-chain compounds. They are subdivided further

according to the “hydrogen” saturation within a molecule. Molecules with single-carbon bonds are hydrogen

saturated; those with at least one double carbon-carbon bond are unsaturated.

2.1.1 Open or Straight-Chain Compounds (Alkanes)

Paraffins: These are saturated, straight-chain compounds. Paraffins comprise a larger fraction of most

petroleums than any of the other individual classes. (Example: n-butane)

Olefins: These are unsaturated, straight-chain hydrocarbons that contain one double carbon-carbon bond.

Similar hydrocarbons, but having two, three or more double bonds, are called diolefins or dienes, triolefins or

trienes, etc. Olefins occur only as trace compounds in crude oils but are common to refinery streams after

cracking operations.

2.1.2 Closed-Chain or Ring Compounds (Cycloalkanes)

Napthenes: These are saturated ring compounds and differ from paraffins by the closure of the carbon

chain. Napthenes constitute the second most abundantly occurring series of compounds in most crudes.

(Example: cyclohexane)

Aromatics: These are unsaturated ring compounds, and although fairly common, they occur less frequently

in crude oil than do paraffins and napthenes. (Example: benzene)

2.1.3 Isomers

Isomers are compounds having the same number of identical atoms in a molecule and therefore the same

molecular weight. However, these atoms are arranged in different molecular structures. Isomers are

common among the compounds of carbon but rare among the compounds of other elements. For example,

there are to isomers of butane C4H10.


Updated Dec. 1999

Crude petroleum is a complex mixture of an almost infinite number of hydrocarbon molecules. Because

hydrocarbon mixtures are routinely separated by distillation and since the low boiling constituents are

usually paraffin hydrocarbons, these components can be precisely separated. Heavy components cannot

be separated completely and are usually removed in “cuts” over certain narrow boiling point ranges.

The four basic chemical classifications of crude oils are paraffinic, napthenic, aromatic and asphaltic. It

should be emphasized that crudes never contain entirely one type of hydrocarbon. The U.S. Bureau of

Mines has developed an elaborate method of classification of crude oils. The nine possible classifications

are based upon the API gravities of low boiling and high boiling fractions.

2.2 Phase Diagrams

Phase diagrams describe the vapor-liquid phase behavior of a system. The behavior is described with

pressure-temperature, pressure-volume, and temperature-volume diagrams; however, the P-T diagram is

used most commonly. The following describes only the P-T diagram characteristics of single component

systems. Crude petroleums are multi-component systems, and the hydrocarbon compounds which make

up these mixtures are single components.

2.2.1 Single Component System

The following basic definitions are useful before discussing vapor-liquid phase behavior:

System - a body of matter that has finite boundaries and is isolated from its surroundings. A system

participates in equilibrium. An example: hydrocarbons in a reservoir.

Phase - a portion of a system which is (a) homogeneous in composition, (b) bounded by a physical surface,

and (c) mechanically separable from other phases that may be present. Examples: oil, gas, water, ice.

Properties - the characteristics of a system by which it can be evaluated quantitatively. Properties are

usually defined at a particular time. There are two types of properties - extensive and intensive. Extensive

properties depend on the extent of the system or amount of material involved; an example is volume.

Intensive properties are independent of the extent or size of the system; examples are temperature and

pressure.

Homogeneous System - one whose intensive properties vary continuously and uniformly from point to point

throughout the system and thereby constitute a single phase. Examples: helium in a balloon; reservoir

fluids above the saturation pressure (single phase).

Heterogeneous System - comprised of two or more homogeneous systems (two or more phases) and its

intensive properties change abruptly at surfaces of contact between the phases. Examples: reservoir below

its saturation pressure (vapor and liquid phases); barrel half full or water (air and water phases).


Updated Dec. 1999

Fluids - liquids, gases, and mixtures of the two.

Component - a substance containing only one molecular species. Examples: carbon dioxide, distilled

water, propane. Crude oil is a mixture of components.

State - condition of a system at a particular time. It is determined when all the intensive properties of the

system are fixed. The minimum number of properties of the system are fixed. The minimum number of

properties that must be described to fix all the properties will depend on the number of components and the

phases present in this system.

Equilibrium - the state of a system that exists when its intensive properties remain unchanged with time

while under a given and constant environment. Example: if at a given temperature the vapor and liquid

phases in a cell are brought into intimate contact by agitation, the system is at equilibrium if the present

remains constant with time.

A typical pressure-temperature diagram for a single component system is shown in Figure 1. The vapor

pressure curve (DC) is the backbone of vapor-liquid phase behavior. The vapor pressure is defined as that

pressure which is exerted on the surroundings of a pure component in the vapor and liquid phases in

equilibrium at a given temperature.

Referring to Figure 1, “C” is the critical point at which the intensive properties of liquid and vapor become

identical (highest temperature and pressure at which two phases can coexist—for single component only).

“D” is the triple point at which solid, liquid and vapor phases are in mutual equilibrium. (This region can be

neglected when discussing petroleum reservoirs.) “DC” is the vapor pressure curve (vapor-liquid equilibrium).

“AD” is the sublimation curve (vapor-solid equilibrium). “BD” is the melting curve (liquid-solid equilibrium).

“NBP” is the normal boiling point—that temperature at which the vapor pressure of a component is 14.7

psia.

The “dew point” is temperature and pressure conditions at which an infinitesimal amount of liquid is in

equilibrium with vapor (first drop of liquid). The bubble point is temperature and pressure conditions at which

an infinitesimal amount of vapor is in equilibrium with liquid (first bubble of vapor). Continuity of phases is

demonstrated in Figure 1 and below by a-b-c-d-e-b’. Vapor and liquid phases are distinguishable only along

the vapor pressure curve (a single phase exists elsewhere).


Updated Dec. 1999

Condition Process State

a - vapor

a-b raise pressure isothermally dew point (vapor) at b

b-c isobaric heating vapor (?)

c-d raise pressure isothermally vapor (?)

d-e isobaric cooling liquid (?)

e-b’* lower pressure isothermally bubble point (liquid) at b’

*Temperature and pressure conditions for b are identical to those at b’.

2.2.2 Multi-Component System

Vapor-liquid equilibrium at a given temperature occurs across a pressure range for a multi-component

system. This is unlike that for a single component system where at a given temperature, vapor-liquid

equilibrium occurs at one pressure only.

The qualitative behavior of multi-component systems is more easily understood by examining a two-

component, or binary, system. A schematic P-T diagram for a binary system is presented on Figure 2. The

two-phase envelope for a 50-50 mole % mixture of the two components is shown. The two-phase envelope

differs for different mole % mixtures of the same components. This is demonstrated by the vapor pressure

curves for the two pure components and the locus of critical points.

Referring to Figure 2, CA and CB are critical points for components A and B, respectively; CM is the critical

point for mixture M. Bubble point (d), dew point (b), and volume percent liquid lines (e.g., c) for any mixture

converge to the critical point. Critical pressures for mixtures are often above the critical pressures for both

pure components.

Generally, the size of the two-phase P-T envelope for any binary system depends on the difference between

the molecular weights of the constituents. The larger the difference in molecular weights, the larger the size

of the two-phase envelope.

Normally when pressure on a system is increased isothermally, condensation occurs. Also, when

temperature on a system is increased isobarically, vaporization occurs. When the reverse happens—i.e.,

when vaporization occurs during an isothermal pressure increase, etc.—these are known as retrograde

phenomena.

Figure 3 illustrates typical retrograde behavior for a binary system. The dark areas are the areas of


Updated Dec. 1999

retrograde behavior. Retrograde regions are often more intense for systems with more than two

components. CB is the cricondenbar, the highest pressure at which vapor-liquid phases can coexist. CT is

the cricondentherm, the highest temperature at which vapor-liquid phases can coexist.

Figure 4 illustrates characteristic phase diagrams for typical reservoir fluids.

In a binary system, the equilibrium composition of the liquid phase and the vapor phase at given pressures

and temperatures can be determined from a knowledge of the dew and bubble point conditions for various

mixtures. The quantitative composition of systems with more than two components is more complex, and

the above technique cannot be used to determine phase compositions.

The distribution of each component between vapor and liquid phases for given pressures and temperatures is

represented by the use of equilibrium vaporization ratios, of K-values. the K-value is the mole fraction of the

component in the vapor phase divided by the mole fraction of the component in the liquid phase. K-values

for a given component depend on temperature and pressure and on the overall system composition.

2.3 Flash Vaporization Equation

The basic equations for calculating the composition and relative quantities of liquid and gas in mutual

equilibrium can be developed from two fundamental relationships. The first of these is the concept of

equilibrium, which requires that, for intimately mixed oil and gas phases at any given temperature, the

pressure, the composition and the relative volumes of the phases do not change with time.

The second concept is that of material balance. This concept requires that the total mass of the system is

equal to the sum of the mass of liquid and of vapor phases. Material balance can also be applied for each

component in the system.

From these relationships, we can derive the flash equation:

j = n j = n zj = 1; (1)

S xj = S

j = 1 j = 1 V(Kj - 1) + 1

j = n j = n zjKj = 1. (2)

S yj = S

j = 1 j = 1 V(Kj - 1) + 1

where:

V + L = 1 or derivation is based on one mole of mixture

V = moles of vapor at equilibrium

L = moles of liquid at equilibrium


Updated Dec. 1999

x = mole fraction of component “j” in the liquid

y = mole fraction of component “j” in the vapor

z = mole fraction of component “j” in the system

Kj = yj/xj

With equations (1) and (2), we can determine the amounts of liquid and vapor phases and their compositions

at any condition of temperature and pressure. This can be done for a system of fixed composition or for one

whose overall composition can be described from condition to condition. More specifically, the following

types of problems lend themselves to analysis by the flash equation.

2.3.1 Stage Separation

This refers to the planned separation of oil and gas that reach the wellhead. Flash calculations will

determine or help to determine the gravity, the shrinkage, the gas-oil ratio for stocktank liquid, and the

specific gravity of the gas. When these results are plotted against separator pressure—or combinations of

separator pressure—the conditions for maximum liquid recovery (or some other maximum or minimum

feature) can be determined.

2.3.2 Reservoir Studies

Flash calculations are used to describe reservoir performance where the composition of the system is

known. Most wells known in this category are gas condensate and volatile oil reservoirs. Flash calculations

in the compositional material balance methods will provide the composition of produced fluid and of fluid

remaining in the reservoir, the amount of production, and the effect of injected fluids on these quantities—all

as a function of pressure.

2.3.3 Miscellaneous Applications

In addition to the major applications of flash equations for stage separator and reservoir analyses, the

following are examples of other problems that have been handled:

(a) The effect of gas-lift or a higher than solution gas-oil ratio on vapor and liquid recovery and

composition.

(b) The effect on vapor and liquid recovery of heating the oil.

(c) Deduction of fluid characteristics and hydrocarbon analyses where complete laboratory data are not

available.

The basic data needed for flash calculations are an analysis of the fluid to be handled and reliable K-values.

There are several methods for determining K-values. The best data are obtained experimentally for a given

system, but this is often difficult and expensive. Many systems have been studied and many of these


Updated Dec. 1999

results have been correlated so that they can be used to determine K-values. These published K-value

methods are in wide-spread use today. K-values can also be calculated using certain natural laws, but

these techniques are limited to application below specific temperatures and pressures.

2.4 Stage Separation of Oil and Gas

Fluids flowing from oil and gas wells usually include oil, gas, water, and sometimes small quantities of solid

phase. This separation of these phases is ordinarily desirable and can be accomplished in a variety of

ways.

There are two kinds of processes for liberating gaseous hydrocarbons from the liquid: flash separation and

differential separation. In the flash separation, the gas and liquid remain in contact as pressure is reduced.

In the differential separation, gas is removed as soon as it is liberated from solution. Less oil shrinkage will

usually occur with the differential process.

Stage separation of oil and gas involves a series of separators operating at sequentially reduced pressures.

Liquid is discharged from a higher pressure separator into the next pressure separator. The purpose of

stage separation is to maximize recovery of liquid hydrocarbons and to provide stable liquid effluent.

However, maximum liquid recovery does not always constitute the optimum economic operation.

Conventional stage separators, widely used in the field, provide relatively low liquid recovery. However, they

are inexpensive to operate. A schematic flow diagram for two-stage separation is shown in Figure 5.

Economic factors dictate the number of stages used in a separation process. As the number of stages

increases, the process becomes more differential in nature. The heart of stage separator performance

calculations is the flash calculation. Remember, though, that maximum liquid recovery may not be the

optimum economic criterion.

2.5 Fluid Properties

Reservoir engineers need to know oil, gas, and water properties as a function of temperature and pressure in

order to make engineering evaluations.

Fluid properties can be determined by three methods. The method to be used in obtaining fluid property

data for any analysis will depend on how critical the fluid properties are to the specific analysis.

1. Laboratory examination of reservoir subsurface samples is the most accurate and reliable method.

In this process, the fluid properties are actually measured.

2. Generalized correlations are an inexpensive way to obtain fluid property data and in many cases are

the only source available.

3. Phase behavior computations based on composition analysis provide reliable fluid property data if

careful consideration is given to the limitations of the calculation procedure.


Updated Dec. 1999

Reservoir fluid properties that relate reservoir volumes to surface volumes are:

1. Bo, oil formation volume factor, relates volume of oil at reservoir conditions to volume of oil

measured at stocktank conditions, res bbl/STB. Bo is always greater than 1.0 because of oil

shrinkage.

2. Bt, total formation volume factor, relates the barrels of oil (including dissolved gas) plus the gas that

was liberated between the initial saturation pressure and the pressure of interest to a barrel of

stocktank oil, res bbl/STB.

3. Rs, the dissolved gas-oil ratio, is the scf of gas dissolved at a given reservoir pressure and

temperature, scf/STB.

4. Rsi, the initial dissolved gas-oil ratio, is the volume of gas released when a given volume of

stocktank oil is produced by a particular set of gas-oil separators, res bbl/scf.

5. Bg, gas formation volume factor, relates reservoir volumes of gas to standard surface conditions, res

bbl/scf.

6. Bw, water formation volume factor, is near unity but varies with salinities, pressure, temperature,

and the amount of dissolved gases, res bbl/surface bbl.

7. Vrf/Vbp, the flash shrinkage factor, is the volume of stocktank oil recovered when a given volume of

oil at the initial saturation pressure is processed through a particular set of gas-oil separators,

STB/bubble-point bbl.

Reservoir fluid properties that describe volumetric and physical properties as they vary with pressure in the

reservoir are:

1. Vo/Vbp, oil relative volume factor, compares the oil phase volume of a sample at various pressures

to the volume the same sample would occupy at the initial saturation pressure, res bbl/bubble-point

bbl.

2. Vt/Vbp, total relative volume factor, compares the total hydrocarbon phase volume (oil and liberated

gas) at various pressures to the volume the same sample would occupy at the initial saturation

pressure, res bbl/bubble-point bbl.

3. RL, the liberated gas-oil ratio, shows how much gas evolves from solution at reservoir temperature

as pressure is reduced, scf/bubble-point bbl.

4. Co, oil compressibility, shows how much a volume of fluid at a pressure above the saturation

pressure will expand per unit of pressure reduction, vol/vol/psi.

5. Ho, oil viscosity, is needed to describe fluid movement and is usually determined experimentally

from PVT tests, cp.

6. Hg, gas viscosity, is generally based on correlations and is used in fluid flow calculations, cp.

7. Hw, water viscosity, varies primarily with temperature and is used in fluid flow calculations, cp.


Updated Dec. 1999

3.0 FLUID FLOW IN PIPING

3.1 Fluid Flow Theory

The following definitions are useful in understanding the theory of fluid flow in piping.

1. Viscosity is the property of a fluid which indicates its resistance to shearing. It is a

dynamic property, in that it can be measured only when the fluid is in motion.

There are two expressions of viscosity, absolute (or dynamic) viscosity µ (mu) and kinematic viscosity, v

(nu). These expressions are related by the following equation:

v = µ p

where p (rho) is the density of the fluid.

Standard units for viscosity are:

µ = dyne-sec = poise = 100 centipoise

v = cm2 = stoke = 100 centistoke

Fluid viscosity changes with temperature. Liquid viscosity decreases with increasing temperature, whereas

gas viscosity increases with temperature. Figure 6 shows the effect of temperature on the viscosity of

several fluids. Changes in pressure at constant temperature have little effect on viscosity. Gas viscosity is

of little importance in practical fluid flow problems.

2. Specific gravity of a liquid is the ratio of density of the fluid at 60 degrees F to the density

of water at 60 degrees F. The API gravity scale is related to specific gravity by the following

equation:

degrees API = 141.5 - 131.5 spec. gravity

The specific gravity of a gas is the ratio of the density of the gas to the density of air. It may be related to

the molecular weight by the following equation:

S.G. = M * 28.96

3. Reynolds Number is a dimensionless parameter which is useful in describing fluid flow:

Re = V D p = VD

µ v


Updated Dec. 1999

4. Flow Regimes describe the nature of fluid flow.

There are two basic flow regimes for flow of single phase fluids: laminar (or streamline or viscous) flow and

turbulent flow. Laminar flow is characterized by little mixing of the flowing fluid and a parabolic velocity

profile. Turbulent flow involves complete mixing of the fluid and a more uniform velocity profile. Laminar flow

has been shown by experiment to exist at NR < 2000 and turbulent flow at NR > 4000. Between Reynolds’

numbers of 2000 and 4000, a transition zone exists in which flow may be either laminar or turbulent.

Prediction of fluid flow behavior is based on the following fluid flow principles:

(a) Continuity equation is a description of the conservation of mass:

y1 A1 V1 = y2 A2 V2

where y is the specific weight, A is cross-sectional area, and V is velocity. For incompressible liquids,

A1 V1 = A2 V2.

(b) Momentum equation is based on Newton’s second law of motion, F = Ma:

F = p QV

where F is force, p is density, Q is the volumetric rate of flow, and V is velocity.

The energy (or Bernoulli) equation is a description of the conservation of energy:

Kinetic energy or velocity head (2g) + pressure energy or pressure head (P/y) + potential energy or elevation

head (Z) + heat energy + mechanical energy = head loss or friction loss = constant.

In most pipeline problems, this equation reduces to pressure head being the sum of elevation head and

friction loss.

3.2 Single Phase Flow

3.2.1 Flow of Liquids

The head loss for liquid flow due to friction in circular pipes is described by the following equation:

hf = f L V2

D 2g

where L is the length of pipe, D is the diameter, V is the average velocity, g is the acceleration of gravity,

and f is the dimensionless. Moody resistance coefficient. (The resistance coefficient is sometimes

expressed in terms of the Fanning friction factor, which is one-fourth of the Moody coefficient.) In theory,

this equation applies only to laminar flow, but in practice it may be used in all flow regimes by using the

correct value of f.


Updated Dec. 1999

The resistance coefficient f is a function of the Reynolds number NR, and the relative roughness of the pipe,

e.

D

For laminar flow, f is a function of NR: f = 64 (NR < 2000).

NR

For turbulent flow, f is a function of both the pipe roughness and the Reynolds number; however, at high

values of NR, f is a function only of e.

D

Figure 7 is the Moody Resistance Diagram, which shows the relationship of f, NR, and e.

D

Figure 8 shows the relative roughness for various sizes and types of pipe.

Expressed in oil industry units, the liquid head loss equation becomes:

hm = 0.13985 fQ2 or Pm = 8.567 fQ2

D5 D5 (131.5 + °API)

where: hm is the head loss per mile (ft.)

f is the dimensionless Moody resistance coefficient

Q is the flow rate (bbls per day)

D is the internal diameter (inches)

Pm is the friction loss per mile (psi)

A disadvantage of the above equations is that both the head loss and f are functions of D, prohibiting a direct

solution for D without resorting to trial and error. The Hazen-Williams equation overcomes this

disadvantage:

Q = 0.094286 CD2.63 hm0.54

However, the Hazen-Williams discharge coefficient “C” must be carefully chosen to reflect both fluid

viscosity and pipe roughness.

In many pipeline problems, pressure drop in pipe fittings (bends, expansions, contractions, etc.) and valves


Updated Dec. 1999

must be considered. It is often simple to treat valves and fittings in terms of their equivalent length of pipe, L

= KD/f. Figures 9 and 10 summarize the equivalent length for various commonly used valves and fittings.

3.2.2 Flow of Gases

Isothermal flow of compressible fluids is described by the following equation:

P12 - P22 = p1V12P1 2 1n P1 + f L

P2 D

Converting to practical units; and ignoring the log term, which is insignificant in long pipes:

Q = 33.7 To E (P12-P22) D5 ½

Po GZafLTf

where: Q = gas flow rate, ft3/day (at To and Po)

To = temperature base, oR

Po = pressure base, psia

E = efficiency factor

P1 and P2 = upstream and downstream pressure, psia

D = internal diameter, inches

G = specific gravity (air = 1.0)

Za = average compressibility

f = Fanning friction factor (.25 x Moody friction factor)

L = length (miles)

Tf = average flowing temperature, oR

The average compressibility should be calculated at the average pressure, Pa:

Pa = 2 P13-P23

3 P12-P22

A number of empirical gas flow equations have been developed. These equations are patterned after the

above general flow equation, but they express E and f in empirical terms based on the experience from

which they were derived. Described below are two of the more common gas flow equations:

1. Weymouth equation:

Q = 433 To (D2.6667) P12-P22 ½

Po GTfLZa

In this equation, f ~ 1

D1/3


Updated Dec. 1999

Since the friction factor is a function only of diameter, this equation is applicable for fully turbulent flow in

commercially smooth pipe. In 80 field tests of lines 8” to 30” diameter and pressures between 15 and 1400

psia, this equation predicted an average of 6% less throughput than measured. Industry experience

indicates that Weymouth’s formula represents average capacities of clean commercially smooth steel

pipeline; however, the friction factor used by Weymouth is generally too low for large diameter lines.

2. Panhandle Eastern “A” equation:

Q = 436E T0 1.07881 D2.6182 P12-P22 .5394

Po G0.8539TfL

This equation is based on tests in a 24” line. In this equation, 1/f~ (GQ/D) 0.1461. Since this equation

depends on Reynolds number, it is not based on fully turbulent flow. No compressibility is included

explicitly in the equation; it is accounted for in the empirical constants and exponents.

The recommended efficiency factor E = 0.92. In practice, the 92% efficiency has been found to be too low

for large diameter lines and too high for small pipe.

The above equations apply only to level lines. For lines with significant elevation changes, the general gas

flow equation must be rewritten:

Q = 33.77 To E (P12-esP22) D5 ½

Po GZafLTf

where s = 0.0375 G *?h and *?h = elevation change (ft).

TfZa

*Nancy’s note: symbol for an open spaced pyramid (triangle) not found on fonts/codes.**

This equation assumes uniform slope; a line over undulating terrain should be divided into a number of

segments of approximately uniform slope before applying the equation.

3.3 Two Phase Flow

The following definitions are terms commonly used in discussions of two-phase flow in pipes.

1. Flowing (or input) liquid fraction (?) is the ratio of liquid input volume to total input volume,

both volumes being measured at pipeline conditions.

(?) = 1


Updated Dec. 1999

1 - 0.005 ZT (GOR)

BoP

where: Z = super-compressibility factor

T = flowing temperature (degrees oR)

GOR = input gas-oil ratio (Scf/STB)

Bo = oil shrinkage factor (bbls/STB)

P = flowing pressure (psia)

2. Superficial velocity ( µ ) is the apparent velocity of fluid flow, ignoring excess liquid.

µ = 0.012 Q1Bo ?D2

where: µ = superficial velocity (ft/sec)

Q1 = input liquid flow rate (STB/day)

D = internal diameter (in)

3. Liquid holdup (a) is the actual liquid volume fraction in the pipe. It is normally larger than

? due to slippage of higher velocity gas past lower velocity liquid.

4. Excess liquid (e) is the liquid fraction in the pipe in excess of the input liquid fraction.

e = a - ? ?Code? ?Code? - ?Code?

1 - ?Code?

5. Froude Number (NFR) is a dimensionless term useful in two-phase flow.

NFR = µ2 = 52.8 x 10-6 Q1Bo 2

gd D5 ?COde?

3.3.1 Two-Phase Flow Regimes

The nature of two-phase (gas and liquid) flow may be illustrated by examining the flow patterns which have

been observed to occur as shown in Figure 11.

(1) Stratified flow: Liquid flows at the bottom of the pipe and gas at the top, with a smooth interface.

(2) Wave flow: gas slippage over the liquid begins to create waves at the interface.

(3) Slug flow: liquid moves in periodic slugs; the liquid may occupy the full cross-sectional area, or the

tops of the slug may be frothy. (Refer to slug, plug, and bubble flow on Figure 11.)


Updated Dec. 1999

(4) Uniform flow: (also spray or dispersed flow) the liquid is dispersed in the gas.

(5) Annulus flow: the liquid flows as a film around the perimeter of the pipe, with gas in the center.

The most commonly used flow regime map was developed by Baker and correlates the various flow regimes

with liquid and gas flow rates and densities, liquid viscosity, and surface tension (Figure 12). Many other

flow pattern maps are available, but in general they give similar results. Since liquid holdup and pressure

drop are not dependent on flow regime, the main uses of these observations are (1) achieving a better

understanding of two-phase flow, and (2) predicting the effect on downstream facilities (e.g., foaming or

slugging in separators).

3.3.2 Pressure Drop Predictions

Pressure drop in two-phase flow is due to energy transfers between the two phases at the interface, and the

reduced cross-section available for each phase, in addition to the normal pipe-fluid friction losses.

The basic pressure drop equations for two-phase flow are also based on momentum and continuity balance

principles. They do not have direct analytical solutions since the terms are an empirical function of pressure

and other variables. The solution must be obtained by a numerical approximation and so is almost always

solved by computer.

As with single phase flow, empirical relationships must be developed, however, two parameters must be

determined instead of one: the liquid holdup and the two-phase friction factor.

Many correlations have been published for estimating the pressure losses which will result when gas and

liquid flow simultaneously in horizontal or inclined pipes. Few of these are reliable beyond the ranges of

variables used to develop the correlations into a single hybrid model to take advantage of correlation

strengths and avoid their weaknesses.

Vohra, et al. evaluated friction factor and liquid holdup correlations for horizontal two-phase flow using

measured data. They concluded that the Dukler and Beggs and Brill friction factor correlations were the

most reliable and that the Eaton, et al. and Beggs and Brill liquid holdup correlations were the most reliable.

Experience has shown that these correlations in general will bracket the correct answer. Normally the

Dukler correlation will tend to slightly under predict pressure loss. In some ranges of flow variables, the

opposite is true.

Pipelines are never precisely horizontal and frequently follow the natural contours of the ground or seafloor.

Elevation changes must be considered in predictions of two-phase pressure drop. Uphill flow is normally in

the intermittent (slug flow) regime, and pressure drop due to the elevation change is a function of fluid

densities, liquid holdup, and the amount of elevation change. Downhill flow is normally stratified, resulting in

a zero pressure loss, as the liquid layer adjusts to the critical depth at which the static head balances the


Updated Dec. 1999

friction loss. However, slug flow may also exist in downhill lines, and may result in pressure recovery (net

pressure gain).

The Dukler and Beggs and Brill correlations will probably also perform better than other correlations for the

hilly terrain pipeline. Since the Dukler correlation was developed for horizontal flow, it is normally combined

with the Flanigan correlation to account for pressure loss due to hills. This approach will frequently over

predict pressure loss due to hills since it ignores any pressure recovery on the downhill slopes of hills. The

Beggs and Brill correlation accounts for inclination effects through corrections to the horizontal liquid holdup.


Updated Dec. 1999

4.0 OPERATIONAL CONSIDERATIONS

4.1 Single Versus Two-Phase Lines

A pipeline cannot be efficiently designed except as a part of a production system. The production system

must be defined in order to decide between single or two-phase lines. Many combinations of pumps and

lines can deliver a given amount of oil and/or gas over a specified distance. The optimum combination of

pump horsepower and line size must consider a number of factors, including investment, operating cost,

equipment availability, and flexibility for future expansion.

Two-phase systems have advantages of economy of scale through centralized separation, pumping, and

compression facilities and through use of one large pipeline instead of two smaller lines. Single-phase

systems may have advantages where there are size limits in pipelines, where lines are very long, or where

the gas or oil sales point is located in the field.

Conditions which favor two-phase lines are:

(1) Most wells make their allowable at pressures which allow flow to shore in a two-phase pipeline.

(2) Two-phase systems allow the substantial investment in pumps, compressors, separators, and the

second pipeline required for single-phase flow to be deferred until the field has been defined and

developed.

(3) The high cost of installing and operating offshore and subsea facilities favors centralization of

facilities.

The trend today is toward two-phase gathering to a central offshore facility, with single-phase lines to shore.

Conditions which favor this trend are:

(1) Production at capacity gives incentive to lower flowing wellhead pressures.

(2) Due to greater distances from shore, oil pipelines are more likely to be common carrier, single-

phase lines.

(3) Competition among gas purchasers make an offshore gas sales point more likely.

Use of two-phase lines presents unique operating problems which are of no concern in single phase line

operation. Liquid accumulations in valleys, increased slugging tendencies, changing composition of “held-

up” liquid, and pressure surging all occur in hilly terrain, two-phase lines.

If the liquids form long slugs, separation and storage facilities must be capable of handling the largest

possible slug. Slug flow is also frequently characterized by large fluctuations in pressure at the outlet end of

a pipe. Although the size of slugs and magnitude of pressure fluctuations cannot be predicted with any


Updated Dec. 1999

degree of reliability, the presence of slug flow or other flow regimes can be predicted. Experience has

shown that a positive pipeline inclination angle (uphill flow) tends to promote slugging, whereas negative

angles promote stratification of the gas and liquid. Liquid holdup is greatest at low flow rates, and

decreases as flow rate increases. This results in a phenomena known as “excess liquid slug,” and explains

the upsets (e.g., separator carryover) which can occur when the flow rate in a two-phase line is suddenly

increased.

4.2 Natural Gas Hydrates

Gas hydrates are ice-like solids formed from free water in the presence of some natural gas components. If

they form in tubing and lines they can cause flow restriction or complete stoppage.

Hydrates resemble ordinary ice when formed without agitation, and resemble wet snow otherwise. The

hydrates are not chemical compounds but rather chemical combinations where one component (gas) fits

into a cage-like cavity formed by the other (water). Hydrates can form at temperatures above the freezing

point of water, and because they behave like solid solutions rather than chemical compounds, they readily

decompose when conditions are unfavorable for their existence.

There is a physical limit to the size of the cavities within the water lattice framework, limiting the hydrate-

forming gases to those molecules small enough to fit into the voids (the normal butane molecule is the

maximum size along with carbon dioxide and hydrogen sulfide). Each hydrocarbon exhibits a predictable

pressure and temperature relationship that is favorable for its formation into a hydrate.

When a mixture of hydrocarbons exists, pressure and temperature conditions for hydrate formation have

been estimated based on the specific gravity (see Figure 13). A method is shown in the NGPSA Data Book

for the prediction of hydrate formation for any hydrocarbon mixture by the use of vapor-solid equilibrium

constants.

The primary conditions which promote hydrate formation are:

Gas composition with “free” water present

Low temperature

High pressure

Secondary considerations which can influence hydrate formation are:

High velocities

Pressure pulsations

Agitation

As mentioned above, hydrates exhibit predictable formation characteristics and have no strong chemical

bonds, so they readily decompose when conditions are unfavorable for their existence. Therefore, it is

possible to reliably prevent hydrates by controlling the variables which influence their formation. The


Updated Dec. 1999

available alternatives to prevent hydrate formation are:

Maintain the gas temperature above the hydrate formation temperature

Operate at lower pressure

Dry the gas so that no free water exists

Inject substances which depress the hydrate formation temperature

The temperature of the gas can be controlled by using line heaters or by hot water tracing of the

transmission lines. Lowering the operating pressure is not normally used because of wasted horsepower.

Drying the gas at the wellhead is done using solid desiccants of hygroscopic liquids. The most common

method for preventing hydrate formation in lines is chemical injection. Various chemical when added to and

dissolved in water can lower the formation temperature of hydrates.

Methyl alcohol, the glycols, various salt brines and ammonia have been used to inhibit hydrate formation.

The corrosiveness of salt brines and drystallization from solutions rule them out as effective inhibitors.

Ammonia is an effective hydrate inhibitor, but if carbon dioxide is present, it forms solid compounds, causing

lines to become plugged. The chemicals used most extensively as hydrate inhibitors are methyl alcohol

(methanol) and ethylene glycol.

Methanol is used as a pure component and has a freezing point less than -100 degrees F. Ethylene glycol

is used in a 70% to 80% aqueous solution because of its freezing point characteristics (see Figure 14). The

viscosity of methanol is much lower than aqueous ethylene glycol solutions, as shown in Figure 15.

Some of the general advantages of using methanol as a hydrate inhibitor are:

Efficient inhibitor

Low cost in comparison to the glycols

Readily available

Easily handled in cold weather due to low viscosity

Remains fluid at very low temperatures (-100 degrees F and below)

Some of the disadvantages normally associated with using methanol are:

Cannot be recovered

Consumption can be high if liquid hydrocarbons are present

Production must stop immediately if injection shuts down

There are several different chemical variations within the glycol family that have been used as a hydrate

formation temperature depressant: ethylene, diethylene, triethylene, and tetraethylene glycols. Ethylene

glycol is most widely used based generally on the following advantages of ethylene glycol compared with

other glycols:


Updated Dec. 1999

Least expensive

Least soluble in liquid hydrocarbons

Lowest viscosity at the low temperatures involved.

Lowest freezing point of its water solutions

Some of the general advantages of using ethylene glycol for hydrate inhibition are:

Minimum solubility in liquid hydrocarbons

Largely recoverable and reusable

Tends to coat the flowline, thus production can continue for a short period of time if injection is

terminated.

Some of the disadvantages typically associated with using ethylene glycol are:

Relatively high cost

Requires dilution with water for use in cold temperature

Requires storage above 25 degrees F for pure glycol to avoid freezing

4.3 Paraffin

Flow restrictions in tubing and lines can also be caused by the formation of paraffin waxes from crude oils.

These waxes typically contain 25-25% oil, 45-55% paraffin, and 10-15% gums and resins. Often a large

proportion of the deposition is made up of water, fine sand or shale, and precipitated salts. Certain

conditions of temperature and pressure as well as the roughness condition of the pipe walls cause

deposition of the paraffin wax. The solubility of the wax is commonly decreased during production because

of the drop in pressure, heat loss to the surroundings, and loss of lighter fractions of the crude.

Several methods can be used to prevent or remove paraffin buildup. Some of the more common ones are

discussed below.

Production Methods - A typical production method employs back pressure to prevent loss of lighter fractions

from the crude oil. This loss generally accompanies its transport from the hole pressure to atmospheric

pressure. The choice of tubing and line size and flow rate has an effect on wax deposition.

Mechanical Methods - These include all those methods which involve using some sort of tool to scrape the

paraffin off after it has been deposited. A number of such tools have been designed, including the “paraffin

hook,” the “paraffin knife,” and the “flow devil.”

Heat Application Methods - Various hot petroleum liquids, as well as hot gas, steam, and hot water, have

been circulated to raise the temperature and either melt the deposited paraffin or increase the solubility.

Solvent Methods - These involve the use of chemicals in which paraffin is highly soluble to dissolve the

deposited wax and to prevent more wax from precipitating. The use of pour-point depressants is related to

this method, although it is generally believed that such depressants do not actually affect the solubility.


Updated Dec. 1999

4.4 Sand Protection

The production of even very small quantities of sand is a condition which can present many problems.

Some wells sand up and cease producing within a few hours if sand-control measures are not provided.

Other wells produce less sand but require sand-exclusion provisions to avoid repeated workovers to remove

the sand from the wellbore. Furthermore, sand production normally will cause a high rate of wear on

subsurface and surface equipment owing to the abrasive effects of the sand particles. In areas where well

pressures are high, the risk of serious trouble frequently makes it necessary to shut in wells which produce

sand until steps can be taken to prevent the inflow of sand. In addition, extra treating costs to remove the

sand may be incurred, and often special surface facilities must be provided to facilitate sand handling and

removal.

Sand difficulties in oil and gas wells usually occur in areas where the producing sane is loosely consolidated

and poorly cemented. In such areas, special completion methods and equipment must be applied to

preclude the entry of sand without harmful restriction of oil production. In some circumstances, these

measures must be applied upon initial completion of the well, and in others, the sand difficulties develop

later in the productive life of the well after reservoir pressure and temperature have declined and, in particular,

when water invasion of the reservoir has occurred.

The exclusion of unconsolidated sand from wellbores is extremely difficult in some cases. Coarse, clean,

well-sorted sand presents the most difficult situation. Other factors, such as type of fluid produced, fluid

viscosity, and rate of flow, also have an effect on the severity of the problem. No one method of sand

exclusion has proved universally successful. The most commonly used methods are slotted liner, wire-

wrapped-screen liner, gravel packing, and sand-consolidating plastics. Sand control by gravel packing has

proved to be the most effective method in the majority of fields with severe sand problems.


Updated Dec. 1999

PRODUCTION FACILITIES

TABLE OF CONTENTS

1.0 INTRODUCTION ................................................................................................................... 1

1.1 Fluids Produced ............................................................................................ 1

1.2 Quantity and Pressures Encountered .............................................................. 1

1.3 Space Allowed On Site.................................................................................. 1

1.4 Producers’ Preferences .................................................................................. 1

1.5 Lease Agreements ........................................................................................ 2

2.0 DESCRIPTION OF VARIOUS COMPONENTS ........................................................................ 3

2.1 Manifold........................................................................................................ 3

2.2 Separators .................................................................................................... 3

2.3 Electrostatic Treater ...................................................................................... 5

2.4 Filter Separator ............................................................................................. 6

2.5 Glycol Contractor .......................................................................................... 6

2.6 Oily Water .................................................................................................... 6

2.7 Desalting ...................................................................................................... 6


Updated Dec. 1999

LIST OF FIGURES

FIGURE 1. General Flow Schematic

FIGURE 2. Horizontal Separator

FIGURE 3. Vertical Separator

FIGURE 4. Treater

FIGURE 5. Filter Separator

FIGURE 6. Glycol Dehydration Unit

FIGURE 7. Desalter


Updated Dec. 1999

1.0 INTRODUCTION

The general flow schematic shown in Figure 1 depicts a feasible flow diagram for an offshore oil and gas

process facility. It should be noted that not two facilities are identical due to the differences in:

(a) Fluids being produced;

(b) Quantity and pressures encountered;

(c) Space allowed on site;

(d) Producer’s preferences;

(e) Lease agreements.

1.1 Fluids Produced

Many fields produce predominantly either oil or gas. In situations such as these, it is possible that no gas

handling and compression equipment would be required or, conversely, no oil separation and pumping

facilities.

Other fields may require special facilities to deal with production problems such as hydrogen sulfide, carbon

dioxide, salt, sand, wax, paraffin, hydrates, etc.

1.2 Quantity and Pressures Encountered

Fields with a great deal of wells at one pressure or with a predominant production may require more vessels

working in parallel or series to handle the particular field. Fields with high pressure gas may not require

compression facilities.

1.3 Space Allowed On Site

Due to the limited area available on most offshore plants, certain functions may be delayed or skipped all

together in order to avoid the high cost of furnishing more on-site area. Typically, on an offshore structure,

produced water will remain with the oil until the production reaches land. This eliminates the need to polish

or clean the water on-site before disposing overboard. Once on land, these cleaning vessels (which typically

are rather large and heavy) can be inexpensively operated.

Another way to avoid extensive offshore areas is to combine the production of various platforms or fields onto

a central facility before various functions are performed.

1.4 Producers’ Preferences

Many companies will regularly use one type of production technique, controls scheme or piping/valving

arrangement, whereas another company will regularly rely on other approaches.


Updated Dec. 1999

1.5 Lease Agreements

Quite often, various wells within one field will be owned by different parties. In situations such as these,

additional vessels may be required such as LACT units (Lease Automatic Custody Transfer) that

automatically tally various wells’ output.


Updated Dec. 1999

2.0 DESCRIPTION OF VARIOUS COMPONENTS

In order to understand the functioning of the process facility, it is best to study each component individually.

The following, therefore, is a discussion of each component of the plant.

2.1 Manifold

The purpose of the manifold is to channel the flow from various wells into the proper piping on the structure.

The manifold, quite typically, is broken down into the major operating pressures of the field. Depending on

the individual wells encountered in the field, header banks for high, intermediate and low pressure are

provided. In addition, one or more test headers are provided. Even if at time of installation all wells are

producing at the same pressure, it is good practice to provide additional header banks, or at least blind

flanges for additional banks, should some wells begin to deteriorate.

Wells are choked upstream of the manifold; however, during a shut-down, it is likely that the manifold will

realize the wellhead shut-in pressure. Because of this, it is necessary to provide valves and piping capable

of this high pressure. The velocities in the manifold can quite often become very high. Often the chokes

feed directly into the header itself. For these reasons, it is good practice to fit tees and crosses with bull

plugs or lead targets rather than ells in order to avoid erosion. In addition, pipe wall thickness for erosion

and corrosion allowance, internal velocities, work access, etc., should all be considered for a good manifold

design.

For reference and guideline, to design a manifold one should refer to API RP 14 E.

2.2 Separators

The major vessel of a production facility is the separator. Separators can either be used to separate the

fluids from the gases (two-phase) or the water from the oil, from the gases (three-phase). The internals of

separators vary from one manufacturer to the next and from one production composition to another.

Separators can be either horizontal or vertical in design.

Horizontal separators, as used in the flow schematic, are used for high to medium gas/oil ratio streams,

large volumes of gas and/or liquids, foam problems and liquid/liquid separations. A cut-away of a horizontal

separator is shown in Figure 2. This design is typical in that the initial momentum of the flow stream is

absorbed by a deflection baffle as the stream enters the vessel. This baffle directs the flow and reduces the

stream’s velocity while the predominantly gas phase rises to the fluid surface. In this design, the fluids pass

through multiple plates of a corrugated matrix. The theory is that in each plate section there are many

shallow inclined channels through which the oil/water mixture passes. Oil droplets then rise to the

undersurfaces of the plates. These small oil droplets coalesce to form progressively larger drops under each


Updated Dec. 1999

plate. As these large drops leave the plate section, they rise rapidly to the fluid surface, while the water

sinks to the bottom.

Once the fluids reach the large holding area, some amount of retention time is available for more fluid

separation.

Gas rises and exits out of the gas outlet. Not shown in the figure, but quite common, is to have a fine wire

mesh “mist extractor” at the gas outlet that helps to eliminate fluid particles leaving with gas. As shown in

figure 1, a back pressure valve is located downstream of the gas outlet which controls the operating

pressure of the vessel.

A weir located well above the oil/water interface allows the oil to flow into a small chamber. In the chamber

some type of float is present to indicate when dumping is necessary.

Located at the oil/water interface is a displacement float that signals the required dumping of the water.

Another form of separator, not shown in the Figure 1 flow schematic, is a vertical separator, as shown in

Figure 3. A vertical separator is generally used for intermediate gas/oil wellstreams. They are more readily

cleaned if sand, paraffin or wax are present. In addition, vertical vessels generally take less deck space and

are therefore useful in limited areas.

Vertical separators work as follows: The mixture of oil and gas enters the inlet where it is given a swirling

motion by a spiral inlet baffle in the separator chamber. At this point there are two forces tending to

separate the oil from the gas. The first is gravity; the second is the centrifugal force caused by the whirling

action of the wet gas. This causes the heavy oil particles to collect on walls of the separator, coalesce and

fall to the fluid.

The gas, which still contains some oil in form of small drops and spray, rises through the chamber. As the

gas enters the swirl cylinder ©, it moves faster and is again caused to whirl so that the oil is forced against

the side of the deflector cone (e). This oil drains down through tubes to the fluid. The gas then passes

through a mist extractor and out the top outlet.

As shown in the figure, this vessel only separates the gas from the fluids (two-phase). However, it is

possible for a vertical separator to be three-phase by adding some form of weir in the fluid section and

providing two dump valves.

The major goal for a separator is to allow the different phases of liquids and gases to separate as thoroughly

as possible. The simplest way to achieve this is to allow the substance to stand still as long as possible.

However, in order to achieve such a long retention time requires a large volume of fluid to be contained, thus

driving up costs and space. For this reason, the various vanes, extractors, plates, etc., have been devised

to keep efficiency up but allow retention time to decrease.

As can be noted in Figure 1, the oil leaving the High Pressure Separators enters the Intermediate Pressure


Updated Dec. 1999

Separator. This vessel, operating at a lower pressure, allows more gas to break out of solution and go into

the atmosphere. This allows the oil to stabilize further. From here the oil continues to the Low Pressure

Separator for even more stabilization at still a lower pressure. By cascading to lower pressures, the

process train is said to be 2 or 3 stages of separation. Some plants may actually have a first and second

stage of a High, Intermediate, or Low Pressure system before the fluids actually intermingle. This is all

determined by the volumes, properties and preferences of the field.

Normally, all the vessels in a field have identical internals and are all rated to operate at the highest

pressure. By having all high-pressure vessels, a great deal of flexibility can be achieved in the process

throughout the plant life. In addition, with bypass piping (normally installed but not shown in Figure 1 for

clarity), maintenance on any one vessel can be achieved without disrupting production.

In addition to the 3 stages of separation shown, there is also a test separator. The test separator is used to

give a regular test to each well to monitor wells’ performances. At the outlet of each phase there is a flow

meter that allows the operator to record the well’s production of water, oil and gas.

2.3 Electrostatic Treater

Following the path of oil from the 3 stages of separation in Figure 1, the oil still contains some water.

Because of agitation, an emulsion is created by dispersion of the water in the droplet form. It is held in this

state by emulsifying agents in crude oil. These agents are generally resins, asphalts, organic acids and

solids which are produced with the oil. They are attracted to the surface of the water droplets and help form

a tough film around them, isolating each water droplet from the others.

This film must be weakened or broken before further coalescence of the water can take place. Chemical

aides, demulsifiers and heat can be used to break the emulsion. In addition, by increasing oil temperatures,

oil density is decreased for more rapid gravitational settling of water droplets. Therefore, the oil flows

through a treater unit as shown in Figure 4.

The treater unit operates as follows: The oil, with the emulsified water, enters over the heating unit. Gas

evolved during the heating is removed through a vent pipe and the emulsion is broken up. The gas-free oil

then flows through a surge section and enters into the electrical coalescing section. Coalescing of the

small water drops dispersed in the oil is accomplished by the high-voltage alternating electrical field. As the

emulsion rises through the field, the water droplets are given an electrical charge. When charged, they

rapidly move about - repelling, attracting and colliding with one another. The droplets collide with sufficient

energy to overcome the now weakened emulsifying forces, and combine into larger and larger drops. This

growth in mass allows gravity settling of the larger drops into the vessel’s water phase. The lighter, clean oil

continues to rise to the top of the vessel where it is collected and removed.

The electrostatic treater, or often called a “Heater-Treater”, is often not used on an offshore platform.


Updated Dec. 1999

Instead, any water remaining with the oil after separation is pumped ashore with the oil. Once on land, a

“Heater-Treater” is used to remove any of the remaining water. This eliminates the rather large, fixed vessel

that requires a good deal of electrical power on the offshore platform.

Oil from the treater continues to a surge vessel and then on to the production pumps through the pig

launcher and into the pipeline.

Facilities are often available, as shown in Figure 1, to recycle the oil should an upset occur in the process

train. The oil will then flow to a holding tank or “bad oil tank” and, once the upset is corrected, back into the

treater.

2.4 Filter Separator

The gas leaving the various stages of production will flow to a filter separator, Figure 5. This device can take

various forms. As shown here, the separator is a double-tube horizontal separator. This vessel is fitted with

extensive mist extractors that work by posing a tortuous course for the wet gas to follow. This allows the

gas to slow down and drop the heavy fluid suspended in it.

2.5 Glycol Contractor

From the separator the gas flows into the Glycol Dehydration System, as shown in Figure 6. This process

is used to remove water vapor from the natural gas. This is done to aid during compression and to avoid

pipeline corrosion.

Wet gas enters a contractor tower at the bottom . High-purity glycol flows down from tray to tray, or through

some sort of low density packing. The glycol absorbs the water from the rising gas.

The now dehydrated gas exits the tower at the top and continues on to the compression package. The

water-rich glycol then enters a series of heat exchangers, is filtered and then finally enters as steam and the

glycol returns to the tower for additional gas dehydration.

2.6 Oily Water

Any oily water that is removed from the various stages of separation or gas filtering will generally be sent to

a series of water-polishing vessels to purify the water so that it can be dumped into the sea or whatever is

available to an on-shore plant. Often the water polishing will consist of another separator. This is often a

vessel that contains a series of corrugated plates that allow the oil to coalesce. From here the water may

enter some form of skimmer tank. These vary in design. On shore, they are often no more than a pit or

settling basin which allows a long retention time. A series of weirs allow the water to flow to cleaner and

cleaner stages while the oil is trapped at the surface by skimmers. Offshore, various forms of the oil is


Updated Dec. 1999

trapped at the surface by skimmers. Offshore, various forms of scrubbers can be used. One in particular

froths the water into a foam. This foam carries with it minute particles of oil to the surface where they are

skimmed.

From here, on an offshore structure the water can go to a sump pile. This is a large tubular member, closed

at the top and open at the bottom, that extends well into the seawater. As the water is dumped into the

sump, any oil remains on the water surface and is trapped by the tube. The clean water is free to pass out

the bottom. A submerged pump is used to direct the oily water back into the system.

2.7 Desalting

Often crude oil is hindered with a high degree of salt contamination. This is typical of Africa, the Middle

East, South America, and Southeast Asia. The salt must be removed before the crude can readily be

handled by tankers, pipelines or storage tanks.

A Desalting Plant, as shown in Figure 7, is used to rid the oil of salt. In this operation, the first step is

typically water removal. This can be achieved with an electrostatic treater as previously discussed.

The second step in the process is desalting. Fresh water is injected to dilute the salty oil; this is then

followed by a second dehydration phase to reduce salt and water content.

The dilution water can be “fresh” or can simply be less salty than the brine remaining in the crude to be

processed. In offshore installations or other areas where fresh water is in limited quantities, seawater can

be efficiently used for dilution.

Dilution water is pumped into the crude stream prior to a controlled pressure reduction to create agitation

and dispersion of the water. Automatic differential pressure controllers, and motor-operated mixing control

valves with trim design to create violent agitation of the liquids through the valves, are used to achieve this

dispersion.


Updated Dec. 1999

WELL OPERATIONS

TABLE OF CONTENTS

1.0 INTRODUCTION ................................................................................................................... 1

2.0 WELL PRODUCING NEEDS .................................................................................................. 2

3.0 WELL FLOWING CHARACTERISTICS .................................................................................. 3

4.0 TUBING FLOW CONSIDERATIONS....................................................................................... 4

5.0 THEORETICAL CONSIDERATIONS FOR VERTICAL TWO PHASE FLOW ............................... 5

6.0 “OPTIMUM” TUBING SIZE ................................................................................................... 7

7.0 CHOKE PERFORMANCE CURVES ........................................................................................ 8

8.0 GAS LIFT............................................................................................................................. 9

8.1 Continuous Gas Lift ....................................................................................... 9

8.2 Intermittent Gas Lift ....................................................................................... 9

9.0 WELL START-UP OF “KICK-OFF”....................................................................................... 11

10.0 WELL MONITORING ........................................................................................................... 13

11.0 WELL KILLING ................................................................................................................... 14

12.0 WELL WORKOVERS ........................................................................................................... 15

13.0 ROUTINE WELL SERVICING ............................................................................................... 16

13.1 Well Preparation .......................................................................................................... 16

13.2 TFL Operations ........................................................................................................... 17

13.3 SSSV Flow Test ......................................................................................................... 18


Updated Dec. 1999

LIST OF FIGURES

FIGURE 1. Well Inflow Performance Relationships (IPR’s)

FIGURE 2. Types of Tubing Flow

FIGURE 3. Tubing Flow Regimes

FIGURE 4. Two Phase Flow Pressure Drop

FIGURE 5. Vertical Two-Phase Flow for 2.875 In. Tubing Set at 8,000 Feet (0 psig Tubing Head

Pressure)

FIGURE 6. Example of Graphical Method for Determining Tubing Pressure Traverse

FIGURE 7. Example of Selecting “Optimum” Tubing Size

FIGURE 8. Best Tubing Size

FIGURE 9. Gas Lift Methods

FIGURE 10. Continuous Gas Lift Principle

FIGURE 11. Gas Lift Valves

FIGURE 12. Gas Lift Valves

FIGURE 13. Gas Lift Valve Setting Depths

FIGURE 14. Shut-in Flowing Well with Dead Oil in the Tubing String

FIGURE 15. Wellhead Pressure vs. Time While Unloading Flowing Well

FIGURE 16. Weighted Fluid Solutions

FIGURE 17. Weighted Fluid Balancing Formation Pressure

FIGURE 18. Typical Well test Separator

FIGURE 19. Wireline Assembly

FIGURE 20. Mechanical Flowsheet for TFL Pumpdown Operations

FIGURE 21. Steady-State Friction Pressure Drop vs. Flow Rate (Measured Data)

FIGURE 22. Tool String Monitoring

FIGURE 23. Tool String Force Developed by Differential Pressure

FIGURE 24. UWC No. 6 TFL System Pressure Falloff Data Field Measurements

FIGURE 25. UWC No. 6 TFL System Calculated Pressure Data

FIGURE 26. Combined TFL Tools String Pulling Force and Impact Force

FIGURE 27. Shear Energy Required for ¼ Inch Steel Shear Pin/Shear Plan (Tensile Test Data)

FIGURE 28. Analysis of TFL Tool String with an Accelerator

FIGURE 29. Kinetic Energy Developed by a Tool String with an Accelerator

FIGURE 30. UWC No. 6 SSCSV Flow Test


Updated Dec. 1999

LIST OF TABLES

TABLE 1. Summary of Terms

TABLE 2. Critical Multiphase Flow through Wellhead Chokes

TABLE 3. Bean Performance Formula for Oil-Gas Mixtures

TABLE 4. Bean Performance Formula for Gas Flow

TABLE 5. Relationship to Calculate Fluid Density Required at 600F to Provide Necessary Density at

Downhole Temperature


Updated Dec. 1999

1.0 INTRODUCTION

This discussion provides basic information for producing well operations. The focus is on oil well operations

because they are of primary interest for subsea or floating production systems.

Methods of providing artificial lift are briefly reviewed. Flowing well characteristics and theoretical

considerations are discussed, followed by determination of “optimum” tubing size. Gas lift principles, well

start-up, monitoring methods, and killing operations are discussed. Also, the types of well workovers and

well servicing methods are discussed.


Updated Dec. 1999

2.0 WELL PRODUCING NEEDS

In the U.S., 90 percent of all onshore wells require some form of artificial lift. Sucker rod pumping methods

are used for economic reasons to meet the vast majority of these needs. However, space limitations of

offshore systems are most compatible with gas lift techniques. Thus, nearly 100 percent of the offshore

artificial lift needs are met with gas lift techniques. Since our major interest is for offshore systems, the

following discussion will only consider flowing wells and gas-lift systems.


Updated Dec. 1999

3.0 WELL FLOWING CHARACTERISTICS

The well inflow system for each producing well depends on several variables, including well drawdown

(pressure difference between the reservoir and the well bore), nature of the fluids flowing, nature of the

formation rock through which the fluids flow, and conditions within the wellbore. Wellbore conditions such

as perforation plugging and impairment due to clay swelling can significantly affect the quantity of fluid

produced. Inter-relationships between these variables is very complex and difficult to calculate. However,

appropriate well tests can be performed to empirically define the net behavior of each well’s inflow system.

Producing rates plotted against pressure at the bottom of the well provides very useful relationship. This

information is called the well’s Inflow Performance Relationship (IPR). As shown on Figure 1, a generalized

curve type relationship can be determined. The curve is due to the presence of more than one phase

flowing. Also, a straight line relationship can be developed based on Darcy’s law for the steady-state radial

flow of a single incompressible fluid. Clearly, the more general curved relationship will exist for most flowing

wells of interest.

The IPR for each well can be expected to change with time as reservoir depletion occurs. This can be due

to decline of reservoir pressure, water encroachment into the reservoir, and several other possible factors.

Thus, well design should consider both near-term and long-term conditions.

Based on this very cursory review of well IPR’s, two important observations can be made. First, lower

surface pressure allows higher fluid flow rates. Second, careful consideration of the total system, including

wellbore completion, tubing selection, surface equipment selection, and the possible need for artificial lift

can result in maximum producing rates.


Updated Dec. 1999

4.0 TUBING FLOW CONSIDERATIONS

One of the most important considerations involves selection of the vertical conduit (or tubing) which is used

to flow the well fluid to the surface. Proper selection of the tubing string size meets two flow objectives.

First, it does not impede high flow rates due to excessive friction pressure drops during the early well life

when flowing rates are potential high. Second, it does not require gas lift to assist well production any

earlier than necessary. These needs are not always compatible, and over-life considerations frequently

require compromise when selecting the tubing size. Offshore well tubing size and gas-lift valve

sizing/spacing are frequently installed on a “best estimate” basis due to limited well performance data.

Major over or undersizing of the tubing should be avoided, due to the high cost of changing out the tubing

string in offshore wells.

The type of flow which exists in the tubing string determines the well bottom hole pressure. As shown on

Figure 2, several types of flow can exist in a tubing string. Several major variables have been combined as

shown on Figure 3 to allow numerically predicting the type of flow regime that may exist. It is apparent that

several types of flow regimes are possible as production flows up the tubing. As demonstrated on Figure 4,

the total pressure gradient consists of two components, head loss due to the density of gas and liquid, and

friction loss due to the flowing gas and liquid. As shown on Figure 4, an important difference exists between

the head-loss controlling and the friction loss controlling portions of the total curve. When head-loss

controlled conditions exist, flow can be unstable. A decrease in velocity (due to downstream shut-in, choke

size reduction, etc.), can cause an increase in the pressure gradient. This can lead to the well “loading up”

and “dying” if it is a weak producer. If it is a strong producer (high shut-in wellhead pressure), this condition

is not of as much concern. Unfortunately, many wells tend to be weak producers.

Typical flowing well performance can be summarized as shown on Figure 5. One dimensional data shown

on Figures A and B represent useful information and are combined in three dimensions in Figure C to give a

good physical representation of vertical two phase flow conditions. In summary, for any constant gas liquid-

ratio, there is a rate of flow which requires minimum intake pressure. Also, for any constant rate of flow,

there is a gas-liquid ratio which provides minimum intake pressure. From this information, it is observed that

column pressure is greatest at low gas-liquid ratios.

Also, for any gas-liquid ratio and depth, there is a rate which requires minimum lifting pressure. This is

because of slippage, and higher rates requiring more lifting pressure because of resistance.

In general, flowing wells with a natural GOR of 1000-1500 or more are not conducive to lowering the bottom

hole pressure (and thereby increasing the fluid rate). Lower GOR wells are excellent candidates for gas

lifting.


Updated Dec. 1999

5.0 THEORETICAL CONSIDERATIONS FOR VERTICAL TWO PHASE FLOW

The usual method for analyzing flow problems is with the law of conservation of energy. Basically, the

change in total energy of a given fluid element as it undergoes a flow process must numerically equal the

energy lost during the process to provide for energy conservation. Equation (1) following, considering only

mechanical energy and expressed in differential form, expresses this relationship (nomenclature is shown

on Table 1):

dp + g sin T dl + VdV + dwf + dwT = 0

__ __ ___

p gc gc

Displacement Change in Kinetic Irreversible External 0

Work + Potential Work + Energy Loss + Work =

Energy (Friction)

For closed conduit flow, the external work team can be omitted. Also, for normal flow velocities, kinetic

energy is negligible. Irreversible loss can be described by equation (2):

dwf = fV2dL 2gcD

The dimension factor f is a function of Reynolds number and tubing relative roughness.

Based on the law of continuity for a compressible fluid flowing through tubing of constant diameter, equation

(3) becomes:

pV + G = constant

so that G, the mass velocity, is an invariant for the flow process. Putting expressions 2 and 3 in Equation 1,

simplifying as indicated, and rearranging gives

dp = g p sin o + fG2

dL gc 2gcpD

Equation 4 states that the pressure gradient in single-phase flow may be considered to arise from the

combination of separate static and dynamic effects, i.e., fluid density and wall friction components. This

relationship can be generalized for two-phase flow. The volume fraction of gas at local conditions within a

two-phase mixture is defined as e. The flowing density of the mixture is then defined by equation (5) as


Updated Dec. 1999

follows:

p mixture = e pg + (1 - e) p1

With appropriate substitution, equation (6) results:

dp = g [epg + (1 - e) p1] sin T + fG2

dL gc 2gcD[epg + (1 - e)p1]

The second term on the right is assumed to account for all internal irreversibilities, particularly those related

to wall friction and relative motion of the gas and liquid. Integration requires separate correlations for e and f,

together with equations of state and property relationships for the gas and liquid phases. Several variations

and modifications have been made to this basic relationship to improve upon the method to obtain better

correlations between predicted and measured values. Fortunately, it is not necessary to manually calculate

tubing pressure gradients. Acceptable results can be obtained using graphical techniques (provided the

graph covers the required conditions) or computer methods, some of which give accurate results provided

that predictions do not exceed the bounds upon which the correlations are based.

Graphical methods generally are presented as shown on Figure 6, with a depth scale on the ordinate and a

pressure scale on the abscissa. Pressure traverses are provided for a given tubing size and liquid rate at

various gas/liquid ratios. Knowing the well depth, wellhead (or bottom hole) pressure, and the GLR, the

pressure traverse for the tubing string can be determined. For the example on Figure 6, given a bottom hole

pressure of 2040 psia, a flowing wellhead pressure of 410 psia would be expected if the well depth is 600

feet.

If computer Timeshare is available, the tubing pressure gradients can be readily evaluated for many

conditions. Appropriate examples and instructions are provided in the WELLFLOW manual, which can be

easily referred to.


Updated Dec. 1999

6.0 “OPTIMUM” TUBING SIZE

As is by now evident, determining the optimum tubing size can be an illusive goal. However, selection of the

tubing size can be based on sound principles and engineering judgement to assure efficient well operation.

One frequently used method to determine the best tubing size is to prepare a plot as shown on Figure 7. In

this example, the goal is to select a tubing size which will allow maximum well fluid production with a

minimum wellhead pressure or 170 psig. In this example, the optimum tubing size could be either the 1.9

inch or 2-3/8-inch tubing. Tubing cost, availability, and compatibility with other well equipment

considerations would determine which size was best.


Updated Dec. 1999

7.0 CHOKE PERFORMANCE CURVES

Well control is most frequently provided by a positive, or fixed orifice size (bean) choke. It is placed

downstream of the wellhead tubing string. For many flowing wells, two possible well rates can occur for

one choke size. As shown on Figure 8A, a tubing head flowing pressure curve and a choke performance (or

characteristic) curve are superimposed.

Position 1 represents stable flow conditions and position 2 represents unstable flow conditions. As shown

on 8B, position 1, if for some reason the choke pressure increases, or decreases, the well inflow conditions

will tend to be returned to the original intersection position, the criteria for stability. However, as shown on

Figure 8C, if the rate decreases slightly for some reason, the net effect is to impose a higher back pressure

on the well. This decreases the well rate and can lead to the well “dying”. Thus, flow conditions are

unstable.

A summary of methods for predicting flow through positive chokes is provided on Tables 2-4. A widely

accepted method for calculating noncritical multiphase flow through wellhead chokes is not available.


Updated Dec. 1999

8.0 GAS LIFT

As discussed above, flowing well capacity may decrease with time for several reasons, most typically due

to decreasing reservoir energy. For offshore wells, gas lift methods can be applied to improve the well

flowing rate and sometimes prolong its economic life. Two types of gas lift are most often applied. The first

is continuous gas lift, and the second is intermittent gas lift.

Continuous gas lift involves use of relatively high pressure gas to increase the fluid gradient, thus allowing

more fluid to enter the wellbore. Intermittent gas lift involves injection of gas beneath an accumulated liquid

slug during a short period of time to move the fluid slug to the surface. Both methods are shown on Figure

9.

8.1 Continuous Gas Lift

The continuous gas lift method is basically much like natural well flow. Gas is injected into the tubing string

to cause an increase in the gas-liquid ratio above the injection point, as shown on Figure 10. Ideally, the

gas is injected at the deepest possible location to provide maximum benefit. Although it would be nice to

inject gas around the bottom of an open ended tubing, pressure limitations generally prevent this. Thus, gas

lift valves are usually installed in the tubing string above TD.

The most common method for gas lifting is to install the valves in the tubing such that gas from the annulus

can enter the fluid in the tubing string. Occasionally the reverse (gas down tubing with fluid up annulus) is

applied for exceptionally high volume wells. It is intended that only one gas lift valve at a time be opened.

For a given tubing size, the gas-liquid ratio that will give the lowest tubing intake pressure becomes

increasingly less as the producing liquid rate increases. The gas-liquid ratio to achieve minimum pressure

becomes very high for low rates of production. When this occurs, intermittent gas lift may be more efficient.

8.2 Intermittent Gas Lift

The gas lift valves can be selected to improve well performance. They can be used to reduce the gas

injection pressure required to “kick-off” or “unload” the well either initially or after an extended shutdown.

They then automatically reestablish the lowest point of injection. Two basic types of injection valves are

used. They are pressure operated or differential. Most are of the former type. As shown on Figures 11 and

12, several types of pressure operated valves are available.

Differential pressure valves operate based on the pressure differential between the tubing and casing

pressures. They are normally open, with the open force provided by a spring. Casing pressure tends to

close the valve and tubing pressure tends to open the valve. When the differential reaches a predetermined

amount, the valves will open.

As shown in Figure 13, an iterative process is used to arrive at the setting depths of the gas lift valves. At


Updated Dec. 1999

start-up conditions, the upper-most valve is closed, and deeper set valves are open due to fluid gradient in

the annulus. As gas pressure in the annulus is increased, the gas enters at the uppermost valve and

decreases the tubing gradient above that point. Annulus fluid is lowered and the gas begins to U-tube

around the next lower gas lift valve. As this occurs, the upper gas lift valve closes due to the decreased

tubing pressure. The process is repeated until gas is being injected at the lowermost valve with all valves

above it closed.


Updated Dec. 1999

9.0 WELL START-UP OF “KICK-OFF”

Well start-up generally is necessary after initial completion, sometimes after extended shut-in periods, or

after well killing or workover activities. In each case, a flowing well can be placed on production using

relatively simple techniques. Most often, this requires knowledge of the well static conditions, including

bottomhole pressure, tubing fluid density, and shut-in pressure.

Figure 14 shows conditions for a well which has been shut-in for a period of time. The tubing is filled with

“dead” oil (gas free) that has accumulated. This well would normally be returned to production by initiating

flow through the well control choke. Figure 15 shows typical flowing pressure as the well comes on

production. Wellhead pressure initially begins to drop as the long column of “dead” fluid moves up the

tubing string. As fresh wellbore fluids enter the tubing string, gas cutting of the column occurs and the

wellhead pressure begins to increase due to the lighter column in the tubing string (and relatively constant

bottomhole pressure). Generally, the wellhead pressure will again decrease somewhat until stabilized flow

conditions exist. A number of variations can occur, particularly with weak flowing wells.

Sometimes, weighted fluids are placed in the tubing string to insure that the well cannot flow to the surface.

This can occur during well completion, workover or killing operations. A brief discussion of typical weighted

fluids follows.

For fluid densities from 9.0 to 11.6 pounds per gallon, clear solutions of calcium chloride in water are most

often used. These fluids are economical and will not precipitate over reasonable periods of time.

Precipitation can cause tubing or perforation plugging, or possible formation impairment. When using these

fluids to balance formation pressure, the effect of wellbore temperature on the fluid density must be

considered. This can be done using the relationship shown on Table 5. Sometimes, higher density fluids

are necessary. These needs can be met with solutions of calcium bromide and calcium chloride in water as

shown on Figure 15. Occasionally, even higher density fluids are required, and these needs can be met

with solutions of zinc bromide, calcium bromide, and calcium chloride in water, as is also shown on Figure

16. The latter solutions are exceptionally expensive.

These solutions are normally used rather than drilling mud because of plugging damage that mud can cause

over an extended period of time. Loss control agents are sometimes added to the weighted fluid solutions

to minimize their loss to the formation. These can be nondamaging filter cake forming materials or viscosity

increasing agents. Whatever is used, it is acid soluble so that it can be dissolved if necessary.

The same wellbore conditions shown above on Figure 14 are shown on Figure 17, but the formation pressure

is now balanced with a weighted solution (neglecting wellbore temperature effects). Wellhead pressure is

zero and the well will not flow, and it is commonly referred to as “dead”.

Several methods can be used to place a dead well onto production. Each requires patience, and some


Updated Dec. 1999

wells will require more patience than others. If the well is equipped for gas lifting, this is the best method to

use. Gas is injected, displacing the kill fluid slowly to the surface and allowing the lighter wellbore fluid to

enter the tubing. As the heavier fluid is displaced, the well will begin to flow using natural reservoir energy

and gas injection can be stopped. The next method involves slowly displacing the heavier fluid into the

formation with a lighter fluid from the surface. This method is frequently referred to as “bullheading” fluid into

the formation. Care must be taken to avoid overpressuring the wellbore equipment, fracturing the formation,

or otherwise damaging the completion. Pump-in is stopped, and the heavier fluid allowed to settle due to

gravity around the wellbore. The well is slowly opened to production, allowing lighter fluid to enter the tubing.

The process must sometimes be repeated many times, or “saw-toothing” before sufficient lighter fluid enters

the tubing and allowing the well to flow naturally.

If gas lifting is not possible and pump-in methods are not feasible due to a deep set standing valve or high

injection pressures, the well can be entered vertically through the wellhead tubing swab valve. Wireline

methods can be used to bail the heavier fluids out of the tubing string. Also, small diameter “spaghetti”

strings can be inserted down the tubing and gas injected down this string to displace the heavier fluid,

allowing the lighter wellbore fluid to enter the tubing.

If the well is equipped for TFL, lighter fluid can be pumped down one string, through the downhole circulation

member, and back up the other tubing string. This is usually done at a relatively high pump rate to displace

the heavier fluid. The well is then allowed to start flowing as described earlier.


Updated Dec. 1999

10.0 WELL MONITORING

Normal well operations include close supervision of the well flowing pressure and well testing. The former is

usually checked at least once per day and the latter performed at least once per month.

Well flowing pressure can provide an early indication of possible downhole changes or problems. Also, if a

more rapid decrease in pressure is observed than would be expected by normal gradual depletion of

reservoir pressure, choke cutting or water entry may be occurring. A pressure increase can indicate a GOR

increase or plugged choke. If a substantial pressure drop exists across the choke, minimum temperature

change will be observed with low GOR production. For high GOR production, a significant temperature

change will be apparent and it may be necessary to inject hydrate inhibitor upstream of the choke to prevent

hydrate blockage at the choke.

Well tests are performed to determine if the well is producing as it should. This information provides

valuable reservoir management information. A typical well test separator is shown on Figure 18. Production

is routed from the well to the test separator where oil, gas, and water are separated and measured.

Conditions are allowed to stabilize, usually for a few hours. During the test period, which is normally not

less than four hours or more than twenty-four hours, the volume of oil, gas, and water is determined. These

results are then expressed in barrels per day for the oil and water, and in thousand standard cubic feet per

day for the gas. Sometimes, the separated oil still has water in it. If so, it is sampled and the dispersed

water content determined. This volume of water is added to the separated and measured water volume and

subtracted from the measured oil volume. The term percent B.W.&W. is frequently used in conjunction with

well testing. It stands for Basic Sediment and Water. Field personnel more often describe it as B. S.

water, which is not the correct terminology. This measurement is made to accurately determine the net

volume of produced oil. Also, results can indicate whether unusual amounts of solids (normally sand) are

being produced.


Updated Dec. 1999

11.0 WELL KILLING

Well killing operations are typically performed to put a well into a non-producible condition. This may be

done in conjunction with well temporary abandonment, preparation of workover operations, or repair of

wellhead or surface equipment. The principle of well killing is to balance (or more often, slightly over-

balance) the formation pressure using fluid of sufficient density. Discussion of these principles was provided

above under Well Start-Up or Kick-Off. In general, it is much easier to kill a well than it is to return it to

production.


Updated Dec. 1999

12.0 WELL WORKOVERS

Several downhole circumstances can cause the need for well workover. These can include depleted

producing zone(s), downhole mechanical failures, and needed tubing size revisions due to changing

producing circumstances.

Frequently, a wellbore penetrates several producing zones. Only one, or a few, of these zones are opened

to the wellbore at one time in most modern-day completions. This is done to assure maximum reservoir

depletion and recovery efficiency. Sometimes, zones behind casing pipe contain producible reserves after

the open zone(s) have been depleted. When this condition exists, a workover will be performed to plug off

the depleted zone(s) and open up zones that are still behind pipe. Also, existing producing zones may have

developed some type of difficulty that can be corrected or improved by workover operations. This can

include early gas breakdown on top of an oil zone, or early water breakthrough (frequently called water

conning) on bottom of an oil zone. Sometimes, these conditions can be corrected by plugging off, or

squeeze cementing, the appropriate section of the producing zone.

Several types of downhole mechanical failures can occur which require workover operations to correct.

These can include wellhead seal failures, downhole safety valve failures, tubing leaks above or below the

downhole safety valve, packer leaks, casing leaks, and completion component (such as gravel pack)

failures.

Changing producing circumstances can also require workovers to best meet current producing needs. For

example, a tubing size which was necessary to meet early high producing rates, may prevent a well from

flowing during later life lower producing rates. Rather than installing gas lift equipment to allow producing the

well, it may be more economical to install a smaller tubing which could allow producing the well to depletion.

For safety reasons, most workovers are performed through BOP equipment. The tree is removed from the

wellhead (normally the well is killed and tubing plugs set first) and the BOP installed. Workover activities

performed, BOP removed, and the tree reinstalled.


Updated Dec. 1999

13.0 ROUTINE WELL SERVICING

During the producing life of a well, a myriad of downhole work through the tubing can be performed. The

most commonly used method for performing this work is with wireline. Sometimes, the wells are equipped

to allow performing this same work using pumpdown tool (PDT) methods, or through flowline (FL) methods.

When vertical well access only is provided, wireline or PDT is used. When horizontal well access is

provided, TFL is used.

Typical wellbore work needs can include paraffin cutting, downhole safety valve servicing, setting or

recovering plugs, standing valves, circulation control valves, gas lift valves or dummies, and shifting sliding

sleeves. Also, bottomhole pressure and temperature measurements can be obtained. Less often, logging

and perforating activities are performed. Also, sand bailing or washing may be performed.

A representative wireline rig-up is shown on Figure 19. The wireline lubricator assembly is mounted on the

tree above the swab valve. If the well is abnormally pressured, or if unusually difficult operations are

anticipated, a small BOP assembly is sometimes mounted between the tree and the wireline lubricator.

The types of wireline components are discussed thoroughly in the various wireline equipment manufacturers’

catalogs. These should be referenced if further information is necessary.

PDT or TFL methods can also be used to perform the well operations provided by wireline. A typical TFL

system is shown on Figure 20. TFL components were described above under the “Well Completion”

seminar. A brief description of TFL equipped well operations follows.

For the TFL system shown on Figure 20, the downhole safety valve requirement is met with a velocity type

subsurface controlled subsurface safety valve (SSSV). Regulations require either that the SSSV be pulled

and inspected annually, or that it be demonstrated that it can be flow closed. This discussion will describe

the TFL operations which would be typically performed to pull the SSSV. It is assumed that this attempt

results in stuck tools which must be recovered and that the SSSV cannot be pulled. Thus, it is tested by

flowing it closed. The SSSV is located below the H-member in the short string (SS) and the long string (LS)

is plugged. Thus, normal production is through the SS standing valve, the SSSV, and to the surface via the

SS, LS, or both.

13.1 Well Preparation

Before performing TFL operations, it is necessary to prepare the flowlines and tubing strings by fluid packing

them and cutting paraffin from the side through which TFL tools will be run. In this application, the TFL

pump is used to pump oil down the SS, with returns on the LS. The adjustable choke downstream of V5 is

used to hold a back pressure on the system so that well fluids do not enter the tubing string. Oil is pumped

down via path 12-3, with returns via 4-5-6 with discharge into the low pressure header. Once the system is


Updated Dec. 1999

fluid packed, paraffin cutting operations can be performed.

With a frequently used closed system, it is sometimes useful to “fingerprint” the hydraulic system. As

shown on Figure 21, the pressure drop under steady state pump conditions is very predictable. If this

information is developed before any paraffin accumulation existed, the measured pressure drop at any later

point in time can indicate whether substantial paraffin accumulations exist. In this particular instance,

paraffin was present in the flowline between the surface and the wellhead. Thus, a TFL tool string is placed

into the SS lubricator at 1. Tree valves would be closed while this operation is in progress so that it is not

necessary to operate above the well shut-in pressure. The tool string would be pumped down the SS until

paraffin build-up is encountered, as indicated by an increase in the pump pressure. The tool string would be

worked back and forth in the SS until the tool string no longer encounters paraffin build-up. In this case,

within a few hundred feet of the wellhead. Tool string location is determined by monitoring pumped volumes

as shown on Figure 22. If the pump rate is not constant, as in this example, it is best just to note the net

pump in volume behind the tool string. Tool string location monitoring methods are not very accurate and

care must be taken not to pump them into closed valves or obstructions at high velocity.

13.2 TFL Operations

After removing the tool string, oil is pumped down the SS, around the wellhead, and into the LS. The tool

string, is dressed out with pump-in/pump-out motors, knuckle joints, accelerator, oil jar (up jar), and pulling

tool. This string is placed into the SS and pumped to the wellhead. This activity also pumps the paraffin

that was cut from the SS through the LS to the surface facilities. After approaching the wellhead, the tree

valves are opened. The tool string is pumped to well bottom (holding a back pressure on the system to

prevent well fluid entry) and the SSSV engaged. Unfortunately, the SSSV and/or lock will not release.

Maximum pulling force on this two-inch system is exerted by pumping down the LS with returns up the SS

(see Figure 23), creating maximum differential pressure across the tool string. Also, unfortunately, the

pulling tool was pinned for shear up release only. This minimizes the chance of accidental down shear pin

release of the pulling tool if the tool string hits the SSSV lock too hard. The can result in a “dry run.” In this

case, a stuck tool string results. Thus, a fishing operation is required to recover the stuck tools.

Careful considerations are necessary to prevent getting the fishing string locked onto the stuck tools with no

means of release. Thus, a brief discussion of hydraulic system dynamics, accelerator/oil jar relationships,

and pin shearing follows.

First, pressure difference across the tool string, which is several thousand feet away, does not happen

instantaneously. As shown on Figure 24, two elements are involved. First, with the system equalized and

pressured up on both sides, pressure is maintained on the LS side and the SS side opened fully. The

pressure wave travels down the SS from the surface to the tool string (SS side only). As shown on Figure

25, by holding 4000 psi on the LS, and allowing the SS pressure to fall off as long as possible, the


Updated Dec. 1999

maximum pulling force (Fp) is obtained. Thus, the oil jar release time should be designed to allow the

maximum pressure difference possible to occur. This effect is represented on Figure 26. Recalling that the

need is to up shear the steel pin in the original pulling tool, Figure 27 shows the amount of shear energy

required per pin shear plane. This device has four shear planes, thus the total impact shear energy would

be 152 ft-lb.

Second, the accelerator is used so that the oil jars do not release into the very long fluid column, which

greatly dampens the magnitude of the resulting “hit”. The operating principle of an oil jar/accelerator

assembly is shown on Figure 28. It is clear that the tool string weight, oil jar stroke, and accelerator spring

constant must be properly designed to provide the required energy to release the pulling tool by shearing the

pin. These relationships are shown on Figure 29.

Thus, the fishing tool assembly is equipped with the appropriate oil jar, accelerator, a high strength shear up

pin (so that the fishing tool string does not release before the stuck tool string) and a shear down release pin

(so that the fishing string can be released if the stuck tool string cannot be recovered). The fishing tool is

pumped down the SS and engages the stuck tools. High pressure is equalized across the tool strings, and

SS pressure is released. The stuck tool string comes loose when the oil jar “hits,” and both strings are

pumped back to the surface and recovered. Unfortunately, the SSSV and lock assembly are not recovered.

Thus, it is necessary to flow test the SSSV closed, shut-in the well, or perform a costly workover. The

former is clearly the most acceptable choice.

13.3 SSSV Flow Test

Flow testing a SSSV closed can be fairly risky. First, the methods for sizing an SSSV are not exact.

Thus, it may be necessary to flow the well at a much higher rate than desirable, particularly if the well has a

potential for producing sand. Second, abruptly stopping the high flow rate and creating a high differential

pressure bottomhole is not desirable. It can cause difficulties for both the completion and mechanical

equipment. These potential difficulties can be minimized by using a modified flow test method.

The tubing strings can be pressured up with oil to above the well shut-in pressure. Then, by quickly

releasing the pressure at the surface, the SSSV will close with only momentary flow—provided the SSSV is

functioning. This operation, including reopening the SSSV by pressuring up on top of it, is shown on Figure

30. Thus, the well can be safely produced and shut-in or costly workover is avoided or deferred.


Updated Dec. 1999

OFFSHORE MOORING AND LOADING SYSTEMS

TABLE OF CONTENTS

1.0 HISTORICAL OVERVIEWS ................................................................................................... 1

2.0 TYPES OF MOORING SYSTEMS .......................................................................................... 3

2.1 The Spread Mooring System .......................................................................... 3

2.2 The Turret Mooring......................................................................................... 3

2.3 The CALM System (Catenary Anchor Leg Mooring) .......................................... 3

2.4 The Rigid Arm CALM ..................................................................................... 4

2.5 Articulated Tower........................................................................................... 4

2.6 The SALM (Single Anchor Leg Mooring) .......................................................... 4

2.7 The SALS (Single Anchor Leg Storage) ........................................................... 5

2.8 The URI Mooring............................................................................................ 5

3.0 RESTORING FORCE AND SYSTEM STIFFNESS.................................................................... 6

3.1 Gravity System ............................................................................................. 6

3.2 Buoyancy System......................................................................................... 6

4.0 MOORING FORCE................................................................................................................ 7


Updated Dec. 1999

LIST OF FIGURES

FIGURE 1. CALM System

FIGURE 2. Exposed Location Single Buoy Mooring (ELSBM) System

FIGURE 3. Single Buoy Storage (SBS) System

FIGURE 4. Shell-Castellon Field Development

FIGURE 5. Spread Mooring Arrangement

FIGURE 6. Turret Mooring Arrangement

FIGURE 7. CALM Rigid Arm System

FIGURE 8. Buoyant Tower SPM Terminal

FIGURE 9. Single Anchor Leg Mooring (SALM) System

FIGURE 10. Buoyant Tower for Fulmar Field

FIGURE 11. URI Mooring System

FIGURE 12. Restoring Force In Gravity System / Restoring Force In Buoyancy System

FIGURE 13. Force/Excursion Diagram for Different Systems

FIGURE 14. Force Generation

FIGURE 15. Mooring Force is Function of System’s Energy Potential


Updated Dec. 1999

1.0 HISTORICAL OVERVIEWS

Offshore mooring systems have been in use since the early sixties. Initially, they were used to load or

unload tankers at locations where no adequate port facilities were available. This way the tanker would

moor some distance from the coast and pump crude oil from or to shore via an underwater pipeline. The

mooring systems were usually located in shallow and fairly protected waters. A single point mooring (SPM)

was primarily used, which allowed the tanker to weathervane around its mooring and take a position of least

resistance to the environment.

The first SPM used for this purpose was the catenary anchor leg mooring (CALM) shown in Figure 1.

Later, the system moved to offshore oilfields where it was used to provide storage for processed crude. A

tanker or barge was permanently moored to the SPM in the vicinity of the platform. The crude was collected

from the platform via a small diameter subsea pipeline and a flexible riser via the mooring system into the

barge. In order to export the crude, a second offloading terminal was placed in the field. Large-diameter

pipelines connected the offloading terminal with the storage barge, allowing unloading of the barge within a

24-hour time span.

The early concepts were used in fairly mild areas where mooring a vessel permanently with simple means

posed no problems.

When operators moved into more hostile waters, such as the North Sea, the storage concept had to be

modified since technology at that time did not permit mooring a vessel permanently in such an environment.

Instead, a combination storage and loading terminal was conceived. The vessel would hook up to the

terminal and receive crude from the platform at the rate of the field production. When the tanker was full, it

would sail to port and another vessel would take its place. When weather conditions became too severe,

the tanker would disconnect and the field would be temporarily shut-in.

The first operator who applied such a scheme was Phillips in its North Sea Ekofisk Field.

Buoy manufacturers started to develop alternatives to the simple CALM which were more suitable for hostile

environments. One development was the Exposed Location SPM (ELSBM), used by Shell/Esso in Aukfield,

shown in Figure 2 which eliminated the floating hose.

Until then, all of these systems were based on the old CALM buoy principle which functioned fine in

conditions for which it was originally intended: Export terminal in mild conditions. Soon it became clear

that the old CALM buoy was not all that great for storage and rough environments.

The main drawbacks appeared to be the use of nylon mooring hawsers and floating hoses. The continuous

wave forces causes fatigue at the hose nipple which could lead to premature hose failure. The nylon hawser

is internally abraded by the cyclic stretch and loses its strength over a period of time. In export terminals,


Updated Dec. 1999

there is ample time to maintain and replace these items between loadings. A permanent storage terminal,

on the other hand, is moored 100% of the time, which speeds up wear and furthermore complicates

replacement. Also, replacement of hawsers and hoses in the North Sea could be impossible for a long

period of time due to adverse weather conditions.

For this purpose, the rigid yoke moorings were designed. The first rigid yoke mooring was the Single Buoy

Storage system (SBS) installed in 1974 offshore Tunisia, and shown in Figure 3.

The advantages are clear: The nylon hawser is replaced by a steel structure with predictable strength

qualities, the floating hoses are eliminated and replaced by hard piping, and the overall motion characteristic

of the tanker is improved. This last point relates the slow oscillatory “fishtailing” of the vessel, which is

normally encountered with hawser moorings.

The stable position of the storage tanker also allows the offloading tanker to moor alongside the barge

instead of using a separate terminal. The crude is transferred directly between the ship’s manifolds.

A dozen or so rigid arm systems of various designs have been installed since then. The desire in later

years to develop marginal fields where a platform was too costly or simply not feasible has led to the latest

development in mooring systems, i.e., the application in floating production systems. Shell was the first

operator to exploit a tanker-based production facility in its Castellon Field offshore Spain in 1977, as shown

in Figure 4. A subsea well produces directly into a permanently moored tanker, where on-board process

facilities separate the oil from gas and water. The oil was stored in the tanker holds while the gas and water

were disposed. Shuttle tankers came alongside the barge periodically to offload the crude.


Updated Dec. 1999

2.0 TYPES OF MOORING SYSTEMS

2.1 The Spread Mooring System

The spread mooring system, shown in Figure 5, uses multiple chains direct from the floating vessel to

(marine) anchors on the seafloor. This system is applicable for symmetrically shaped vessels even in very

deep water as long as the connection method for risers between the seafloor and the vessel can be

designed to accommodate the excursion and motions of the vessel. A spread mooring can also be used for

ship-shaped vessels, but only in calm or unidirectional weather areas. The forces on a ship-shaped vessel

are very large in beam seas and even if the mooring could be designed to hold, the roll motion of the vessel

would pose impractical low operational limits for facilities on board and for people’s general feeling of

wellbeing.

2.2 The Turret Mooring

A single point mooring using chains from a turret on the bow of the vessel to anchors on the seafloor, as

shown in Figure 6, is an alternative that allows the vessel to weathervane. This makes it possible to stay on

location in multidirectional storm conditions. The biggest advantage is easy access from the vessel to the

mooring and fluid swivels in the turret.

The major disadvantage of the bow turret is the limitation in water depth. Heave response of the nose of a

tanker can be 1.5 times the wave height. This vertical motion will cause high dynamic loads in the anchor

chains which becomes more predominant when the ratio of water depth to vertical motion is small. On a

tanker, the turret must extend downward to near the level of the keel of the vessel to prevent the mooring

chains from hitting the bulb on the bow. This further decreases the actual catenary depth, which reduces

the flexibility. The catenary mooring lines can be made longer and thus more flexible for a flat-nosed barge

or by removing the bulb from the tanker. However, in general, the turret mooring cannot be used in water

depths less than 100 feet except in very calm weather.

2.3 The CALM System (Catenary Anchor Leg Mooring)

A single point mooring, where the floating vessel is moored by a hawser to a buoy held in place by mooring

chains (Catenary Anchor Leg Mooring, CALM), is the most common type mooring for offshore tanker

loading. This system was shown earlier in Figure 1. It can be designed to operate in almost any water

depth for a very wide range of sea conditions and vessel sizes. The hawser provides 6 degrees of motion

freedom between the buoy and the vessel, allowing the vessel to move relative to the buoy, and provides

elasticity to absorb some short-period dynamic loads. Both effects reduce the forces on the buoy and the

vessel’s bow. The biggest disadvantage is that the buoy must be connected (for fluid transfer) to the vessel


Updated Dec. 1999

by floating hoses. In rough weather the motions of the floating hose relative to the buoy and vessel are

large, causing high bending stresses in the connection at the buoy and where the hose changes from

horizontal to vertical at the vessel side. Any maintenance work or operation on the buoy requires transport

of people from the vessel by boat. In calm weather the vessel tends to ride up to the buoy, which can cause

damage to the buoy and the floating hose.

2.4 The Rigid Arm CALM

Problems related to the hawser and floating hoses of a CALM can be overcome by attaching the vessel to

the mooring buoy by means of a rigid arm as shown in Figure 7. Articulations between arm and vessel allow

the vessel to pitch and heave independently from the buoy; all other relative motions between buoy and

vessel are eliminated.

A consequence of eliminating the hawser is a reduction in mooring elasticity. In deep water this will not

affect the systems limitations since the chain system alone provides sufficient elasticity.

In shallow water, however, the catenary system becomes less elastic and the hawser will contribute a

greater part to the overall system elasticity. Exchanging the hawser for a rigid arm in that case will reduce

the operational limits of the system.

2.5 Articulated Tower

A buoyant tower, as shown in Figure 8, is connected to the seafloor anchor base through a universal joint.

Hoses or fluid swivels provide a flow path around the articulation. The top of the tower is equipped with a

turntable to which the vessel is attached with a hawser or structural arm.

With increasing water depth, the bending moments in the tower, due to vessel offsets and waveloading,

increase progressively and the structural needs to cope with the bending stresses make this concept

economically prohibitive in water depths greater than 600 feet.

2.6 The SALM (Single Anchor Leg Mooring)

A spar-shaped buoy is held to the seafloor anchor by a chain or a rigid riser. The system using a riser is

shown in Figure 9. The vessel is moored to the buoy. A mechanical swivel at the base of the buoy or a

turntable on top of the buoy allows the vessel to weathervane. A universal joint is provided to reduce the

bending moments at both ends of the riser. Hoses or fluid swivels provide a fluid connection around the

lower universal joint. For a loading terminal, a submarine loading hose brings the fluid from the swivel,

located just below the upper universal joint, up to the moored vessel.

In shallower water, the riser can be eliminated using the buoy as a tower, as shown in Figure 10.


Updated Dec. 1999

For a production riser application, multiple lines are brought around the universal joint below the buoy

through hoses or swivels to the top of the buoy. A multiproduct swivel carries the fluid from the buoy to the

rotating turntable. A rigid arm must be used in this case, since the rocking motion of the buoy and the

relative vertical motion of the water surface would pose severe stress conditions on surface or subsurface

hoses.

The SALM concept can be used in virtually any water depth. Unfortunately, the cost of the system is high

because the buoy will be large and must have a deep draft in order to be stable in the wave troughs.

2.7 The SALS (Single Anchor Leg Storage)

Buoyancy is placed in the arm, connecting the vessel with the riser. The riser is either a torsion stiff chain

or a rigid structure. A SALS using a torsionally stiff chain was previously shown in Figure 4. A mechanical

swivel combined with a universal joint between the riser and the arm allows for vessel weathervaning and all

independent vessel motion. A universal joint at the base of the riser allows the riser to tilt freely. Hoses or

fluid swivels are used to provide a flow path around the universal joints. The advantage of this system is

better performance in shallow water due to increased riser length. The major disadvantage is the fact that

the buoyancy is in the wave zone, which increases the forces on the arm and consequently the structural

weight. This requires more buoyancy volume to provide an adequate riser tension.

In deep water this problem becomes more pronounced since the riser tension has to increase in order to

limit the riser angles. Large riser angles would cause the yoke to move down a considerable amount,

bringing the fluid swivel under water. The amount of buoyancy required to provide sufficient riser tension in

deeper water would therefore be enormous, and the economic use of the SALS is probably limited to water

depths of approximately 1000 feet.

2.8 The URI Mooring

In the URI mooring, as shown in Figure 11, an arm extends from hinges on an anchor base to the lower end

of the riser, which is hung from a relatively small structure on the bow of the moored vessel. The arm is

connected by hinges to the base, which permits only vertical motion of the arm. As the vessel moves away

from its vertical position, the weight at the base of the riser is lifted while the riser inclines, thus providing the

restoring force. Providing the restoring force by weight reduces the displacement of the system (the specific

gravity of steel ingots is about seven times the effective specific gravity of a steel buoyancy tank operated

near the surface). Moving the displacement of the riser from near the surface to near the bottom

significantly reduces wave forces. The smaller submerged volume also reduces the added mass of the

system and consequently the inertia forces caused by vessel motions. The major disadvantage is the

limitations in shallower water depth. In depths less than 200 feet, the system becomes impracticable in

view of the limited system elasticity.


Updated Dec. 1999


Updated Dec. 1999

3.0 RESTORING FORCE AND SYSTEM STIFFNESS

The reaction force from the mooring system on the vessel which tends to pull the ship back to its neutral

position is generally referred to by the term “restoring force.” The restoring force potential of mooring

systems is most commonly based on gravity or buoyancy.

3.1 Gravity System

The most common mooring system is the Catenary Chain Mooring. A vessel or buoy is moored to the

seabed by means of several chain pendants. The chains hang in a catenary shape from the surface to the

seafloor where they continue in the same general direction towards an anchor point (piles, marine anchor, or

gravity.) When the vessel moves away from its central (neutral) position due to environmental forces, the

potential energy level in the mooring system is increased by lifting more chain from the seabed on the

weather-exposed side. A new equilibrium position is found when the increase in potential energy equals the

restoring (mooring) force/excursion energy. This system is shown in the top half of Figure 12.

Another gravity system is the URI Mooring. A weight is suspended from the riser creating a tension force.

When the ship is pushed from its neutral position, the riser inclines and causes a horizontal component of

the riser tension force, which tends to pull the ship back. A new equilibrium position is found when the

restoring force equals the environmental force acting on the vessel.

3.2 Buoyancy System

Unlike catenary systems, buoyant riser systems obtain their restoring force from buoyancy. A riser,

articulated at the seafloor, is pretensioned by a buoyancy tank, located at the riser top. The pretensioned

riser acts like an inverted pendulum when pulled from the neutral vertical position, i.e., the potential energy

in the system increases due to the submergence of the buoyancy tank, consequently resulting in a

restoring force. This system is shown in the lower half of Figure 12.

Restoring force indicates the capacity of the system to generate a reaction. The performance of a mooring

system, however, depends also on the excursion.

The force/excursion diagram, given in Figure 13, shows the system performance and is one of the criteria to

judge whether that mooring system is suitable for a particular environment.


Updated Dec. 1999

4.0 MOORING FORCE

The term “mooring force” pertains to the load between vessel and mooring in a certain environment.

Generally, the mooring force is a function of the following parameters:

vessel size

wave height and period

current speed and direction

wind speed and direction

characteristic of mooring system

Before we address these parameters, the mechanisms of a mooring system should be clarified. The main

purpose of a mooring is to restrain the horizontal motion of the vessel. Absolute restraint is impossible,

however. To limit the wave induced short period motion of the tanker would require forces beyond what is

physically possible. Hence the six degrees of short period vessel motion cannot and should not be

restrained by the mooring system. What can be limited is the long period surge, sway and yaw of the

vessel.

Since the short-period vessel motions dictate an elasticity in the system, the ship will respond to force

variations in the long natural period of the spring-mass system, formed by ship and mooring.

This natural period will affect surge, sway and yaw. The exciting force to this phenomena is caused by wave

drift forces, wave grouping, wind speed variation and direction changes, and current fluctuations.

This force system on the vessel is complex. A wind gust can initiate a yaw motion which will change

relative current heading and wave drift force in its turn. A continuous change in force and moment balance

takes place.

The result of this slow oscillatory motion is that the mooring force will be larger than a static equilibrium

check would indicate. The magnitude of this amplification depends on the characteristic of the mooring

system. A very stiff system will in general induce higher mooring loads; on the other hand, a sloppy system

is equally unsatisfactory since the vessel can built up momentum first, which then causes high inertia loads

when enough restoring force can be generated.

The general tendency is that the mooring force increases with vessel size, wave height, current speed and

wind speed. However, there are certain effects which can upset this generalization. A larger vessel size

can bring the natural period of the mooring system outside the range of predominant wave grouping;

moreover the short period forces become smaller with increasing vessel size. These two effects can result

in a larger mooring force with the smaller vessel.

A short-crested wave, encountered in typhoon areas without sufficient fetch for the sea to fully develop,


Updated Dec. 1999

could cause higher mooring loads than a larger wave with a longer period. When current is running in the

direction of wave propagation and vessel hading, the static mooring force will increase with current speed.

The current will introduce, however, a damping effect which could cause a reduction in long period surge.

When current comes in perpendicular to the waves, the vessel will take a heading somewhere between

waves and current. The current will then generate a lift effect which will push the vessel forward into the

waves and reduce the mooring load.

The characteristic of the mooring system is the keystone in the mooring force concept. Firstly the system

should have enough strength to withstand the mooring force; secondly, the system should yield enough

elasticity to limit the mooring force. This can be clarified with the following picture. Figure 14 shows the

horizontal motion of the system over a period of time. The system makes long period excursions,

superimposed on which are wave-induced short-period motions. Projecting this picture on a typical

force/excursion diagram of a catenary chain system shows some interesting phenomena. Again we find the

quasistatic equilibrium position A with the long-period mooring force, FA. The dynamic motions create a

force variation around this point, the magnitude of which depends on the gradient of the force/excursion

diagram. A small force gradient obviously generates small dynamic forces. A high force gradient could

cause forces far in excess of the breaking strength of the chain.

A measure of effectiveness of the mooring system is the energy potential represented by the (usable) area

under the curve. Figure 15 shows a hypothetical energy curve. A concave curve will yield high quasistatic

and dynamic forces, while a convex curve with the same energy potential will induce smaller forces.

Only horizontal motions have been considered in these graphs; vertical motions, particularly in shallow

water, will h ave similar, and sometimes worse, effects as the horizontal dynamic motions.


Updated Dec. 1999

MARINE SYSTEMS

TABLE OF CONTENTS

1.0 THE SHIPSHAPE.................................................................................................................. 1

1.1 Calculated Properties..................................................................................... 1

2.0 STABILITY........................................................................................................................... 3

2.1 Initial Stability ............................................................................................... 3

2.2 Complete Stability ......................................................................................... 3

2.3 Dynamic Stability .......................................................................................... 4

2.4 Stability Standards ........................................................................................ 4

2.5 Damage Stability........................................................................................... 5

3.0 MOTION............................................................................................................................... 6

3.1 Environment .................................................................................................. 6

3.2 Idealized Environment .................................................................................... 6

3.3 Statistical Analysis........................................................................................ 6

3.4 Vessel Motion Definition................................................................................. 8

3.5 Ship - Environment Interaction ........................................................................ 8

3.6 Drillship - Semisubmersible Comparisons ........................................................ 9

4.0 MODEL TESTS.................................................................................................................... 10

5.0 CLASSIFICATION SOCIETIES ............................................................................................. 14

5.1 Purpose....................................................................................................... 14

5.2 Societies ..................................................................................................... 14

5.3 Covered Items .............................................................................................. 14

5.4 Administration of Government Regulations ...................................................... 14


Updated Dec. 1999

LIST OF FIGURES

FIGURE 1. Ship Planes

FIGURE 2. Lines Plan

FIGURE 3. Table of Offsets

FIGURE 4. Displacement and Other Curves of Form

FIGURE 5. Simpson Integration for Area

FIGURE 6. Simpson Integration for Displacement

FIGURE 7. Cross Section of Typical Floating Body



FIGURE 10. Cross Section of Heeling Vessel

FIGURE 11. Cross Curves of Stability

FIGURE 12. Curve of Statical Stability

FIGURE 13. Righting & Heeling Moment Curves

FIGURE 14. Overturning Moment due to Wind

FIGURE 15. Limiting Downflooding Angle

FIGURE 16. Compartment Flooded for Damage Stability Calculations

FIGURE 17. Floodable Length Curve

FIGURE 18. Load Line Markings

FIGURE 19. Current Profile

FIGURE 20. Regular Wave

FIGURE 21. Linear Spectral Analysis

FIGURE 22. Six Degrees Vessel Motion

FIGURE 23. Heave Rao Curve

FIGURE 24. Tons per Inch

FIGURE 25. Heave Rao Curves Ship vs. Semi


Updated Dec. 1999

1.0 THE SHIPSHAPE

A ship is a 3-dimensional buoy floating on a liquid-gas interface. It floats by displacing an amount of water

equal to its weight. The ship is defined by various linear measurements. The length is measured in the

direction of travel and parallel to the water surface. The breadth is measured perpendicular to the length and

also parallel to the water surface. The depth is measured perpendicular to both the length and the water

surface. Draft is a depth measurement from the lowest point of the body to the water surface. Each of

these measurement types has several specific and different examples.

In order to quantify the shape of the ship, a mapping technique is used. Mutually orthogonal plane sets are

“passed through” the ship and the intersections of the planes with the boundaries of the ship plotted as

shown in Figure 1.

The first set of planes are known as waterplanes. These are parallel to the water surface. The intersection

of one of these planes and the ship produces a waterline.

The set of planes parallel to the length and perpendicular to the waterplanes are called buttock planes and

the intersections are buttocks.

Transverse planes are perpendicular to both the previous sets and result in section lines.

The lines defined above are assembled on a drawing called a lines plan; the waterlines grouped on a half-

breadth plan, the buttocks on a profile plan and the sections on a body plan. An example is shown in

Figure 2.

From this plan, measurements are taken off. These are grouped in a table called a table of offsets as shown

in Figure 3. The table of offsets represents the numerical definition of the shape of the ship. See Figure 3.

1.1 Calculated Properties

With the shape of the ship known, various properties can be calculated. These fall into two types. The first

are related to the underwater volume of the ship and the second to the hull, or shell plating.

The important characteristics of the underwater volume are grouped into one plot as shown in Figure 4:

? or displacement

CB or center of buoyancy

Awp or area of the waterplane

CF or center of flotation

I or waterplane inertia

BM or metacentric radius


Updated Dec. 1999

The above relate to the behavior of the ship. In addition, characteristics may be calculated which indicate

the fatness or slimness of the volume. All of the characteristics are calculated for a specific assumed

waterplane. The most commonly encountered are defined by the design draft.

The characteristics of the hull plating which are determined are the weight of plating, its center of gravity and

its inertia. These properties are combined with a calculation of the weight, center of gravity and inertia of the

ship’s structure, outfitting, consumables and cargo to yield properties for the ship as a whole. This includes

? and CG.

Because most ships have lines which are not mathematical equations, numerical integration techniques

must be used to determine the volume and hull properties. Nowadays, this is done with sophisticated

computer programs and advanced formulas and up until about six or seven years ago, naval architects spent

a great deal of time doing this. The most widely used formula is known as Simpson’s Rule. Figure 5 is an

example of transverse sectional area. This rule assumes a curve is a second-degree parabola. An even

number of equal spaces, n, is imposed on the area to be integrated by (n + 1) ordinates. The area is

considered to consist of n/2 parts, each with a base equal to twice the common interval, S, between

ordinates as shown in Figure 6.

The characteristics of the underwater volume are calculated for various drafts and plotted as shown on

Figure 4.


Updated Dec. 1999

2.0 STABILITY

2.1 Initial Stability

The stability of a ship, or its tendency to float upright, is investigated by comparison of the two types of

characteristics discussed. That is the relation between the underwater volume and the ship itself is

investigated.

The weight of the ship must be balanced by the displaced water. Thus the weight will determine at what

draft the ship floats. At this waterline, the volume of water will have some centroid, B, which is measured

vertically from the keel as shown in Figure 7. The ship has some center of gravity, G, also measured from

the keel. At even keel, the line of action of the weight, through G, lines up with the line of action of the

buoyancy, through B, and there is equilibrium.

Now assume an applied moment cause the ship to roll as shown in Figure 8. At the inclined waterline,

there is a new center of buoyancy. There is now a separation between the line of action of the weight and

the line of action of the buoyancy. This separation is the righting level, GZ. The couple created by the

separation of weight and buoyancy is called the righting moment and is equal to the displacement times the

lever or: ? GZ as shown in Figure 9.

The above discussion refers to a ship with positive stability. This is defined by the metacenter being above

the center of gravity. If this is true, an applied moment will result in a restoring moment resisting heel.

Negative stability occurs when the metacenter is below the center of gravity. An applied moment is now

assisted by the “restoring” moment. It becomes a heeling moment as shown in Figure 10.

The relation of the center of gravity to the metacenter, GM, is calculated from the known properties of the

ship.

GM = KB + BM - KG

KB is the vertical height of the center of buoyancy.

BM is the distance between the center of buoyancy and the metacenter, determined by the inertia of the

waterplane.

KG is the vertical height of the center of gravity.

There is an important correction to this equation which accounts for the effect of liquids in tanks on the ship.

The center of gravity of the ship as used above is assumed constant. If there are partially filled tanks on

board, the effect of heeling will raise the center of gravity of these tanks, thus raising the center of gravity of

the ship. Thus stability calculations include a “free surface” term to correct the KG term.


Updated Dec. 1999

2.2 Complete Stability

The righting arm found in the example before was for one angle of heel, one displacement and one location

of the center of gravity. Since the center of gravity will vary with the loading of the ship, a presentation of the

complete stability is done by assuming a fixed location for the CG. This location is usually referred to as

“S”. Calculations are then done for varying displacements and angles of heel. This results in a family of

curves know as “cross curves of stability” as shown in Figure 11. When a known condition of the ship is

available, the righting arm obtained from the cross curves can be related to the actual righting arm GZ.

The righting arm for the know condition varies with angle of heel and is usually plotted as GZ (feet) versus

angle of heel (degrees). This is a curve of statical stability as shown in Figure 12.

2.3 Dynamic Stability

With the relationship between righting arm and inclination established, a righting moment curve can be

created. This is the righting arm curve multiplied by displacement. The area under the moment curve from

one angle of heel to another is the work involved. This is shown in Figure 13.

The effect of an external heeling moment can now be compared to the restoring moment. If, for example a

wind is blowing against the ship’s beam then the wind and the ship’s hull in the water will produce a couple

tending to overturn the ship as shown in Figure 14. If the ship is initially at rest, the wind will cause heeling

to point A (See Figure 13). This value of inclination is the steady state value. Point B is an unsteady

position. If the angle of heel is increased, the ship will roll over. Point C represents the maximum moment

that can be generated by the ship. Points A and B are referred to as, respectively, the first and second

intercepts.

2.4 Stability Standards

Several criteria may be applied to the stability of a ship. The first, and most obvious, is that the ship have a

positive GM in all expected conditions. Regulatory bodies may specify that this be a certain minimum. In

addition, dynamic stability standards are applied because the ship is not at rest in a windless/waveless

laboratory. One standard requires that the area under the righting moment curve to the second intercept be

130% of the area under a 100 knot wind heeling moment curve to the same intercept. The extra 30% work

involved is to take care of the dynamic effect of a ship rolling from side to side. The second intercept is also

required to be at a minimum of 30°.

Another criteria involves the angle at which the ship begins to take on water through an opening, such as a

hatch. This downflooding angle, as illustrated in Figure 15, may restrict how far the vessel can heel.

In addition to wind as a heeling moment, several other conditions will cause unusual inclination. The

following conditions may also need consideration during design:


Updated Dec. 1999

hoisting of heavy loads over the side

towing

passenger crowding

high-speed turn

The discussion thus far has been about paper characteristics. Once the ship is in the water, a test may be

made to check the accuracy of the calculations. This test is called an inclining experiment. Weights are

moved around on the ship and the change in the heel of the ship is measured. This test ends up relying on

calculated characteristics, however, as the displacement is needed. It’s a very small ship that can be

actually weighed.

2.5 Damage Stability

Ships, being items of large mass operated in an unpredictable environment by human beings, are

occasionally damaged. Although a ship which is damaged and returns to port for repairs takes bread from

the mouths of naval architects, there nevertheless are strong reasons for having a ship survive damage.

Thus, the stability and flotation of a ship is investigated by mathematically damaging the ship. This is

illustrated in Figure 16. For a given ship, compartments are flooded and the impact on heel, trim and

righting moment calculated. Interestingly, two methods used for flotation calculations are the “added weight”

method and the “lost buoyancy” method.

Another set of calculations is performed to derive a floodable length curve. This curve, shown in Figure 17,

represents the maximum length of compartment, centered at point of penetration, which could be flooded

without causing the ship to trim more than an acceptable amount. The trim is without list.

The calculations of damaged condition that a ship has some reserve buoyancy. This is buoyancy not

normally at work but which is needed in a damaged state. To ensure that ships keep enough reserve

buoyancy during operation, they are assigned a load line. This mark, as shown in Figure 18, is on the side

of the ship and indicates the maximum draft to which a ship may be loaded.


Updated Dec. 1999

3.0 MOTION

3.1 Environment

The ship’s environment is a widely varying one. The effect of this environment can be studied by breaking it

down into three segments. Wind is the movement of the air portion. Current is the movement of the water

portion. These are generally defined by steady-state values. Waves are the changing air-water interface.

They are the most difficult part of the environment to define.

3.2 Idealized Environment

Wind is a widely and rapidly varying force. For purposes of design and comparison, wind is usually taken to

be steady at some velocity and direction. Often the velocity is determined by regulatory body dictate in

conjunction with stability requirements.

Current is also a widely varying force, though it does not usually vary as rapidly as wind. It, too, is usually

taken as a steady-state velocity and direction. For drilling vessels, it is important to know the variation of

current with depth. This “current profile” is usually presented as uni-directional as shown in Figure 19.

Often, two profiles are used. The average, or mean, values represent the most commonly expected current.

The maximum values represent either measured short-term extremes or the uncertainty of the measurer.

Waves are caused by a disturbance of the water, either by some physical displacing force or, more

commonly, by the passage of wind. An idealized wave train, as shown in Figure 20, has certain measurable

properties, such as height and length. While regular waves are useful as a means to understanding, they

rarely occur alone. Most sea conditions of interest consist of groups of regular waves superimposed on

each other.

3.3 Statistical Analysis

Because of the random nature of irregular seas, it is impossible to predict instantaneous environmental

conditions. However, statistical techniques enable presentation and use of irregular wave characteristics.

In dynamic marine systems we are dealing with two kinds of quantities:

“linear” quantities

“non-linear” quantities

The first group contains functions which have a linear response to wave height. Short-period system

motions fall in this category. Most of the mooring system parameters, however, fall in the second category.

All the system forces, for instance, are not linear-related to wave height.


Updated Dec. 1999

In order to predict certain maximum design loads, statistical methods have to be applied. A different

approach for the two categories is necessary.

Determination of probability levels for the first kind is straight-forward and is done with the wellknown

spectral analysis technique. Figure 21 illustrates the following relationships.

SZ(w) = HZ(w)2 x S ?(w)

where: SZ(w) = energy spectrum of (heave) motion z

S?(w) = energy spectrum of irregular sea

HZ(w) = response amplitude operation of z relative to the wave amplitude ?a(w)

From the heave spectrum SZ(w), it follows that:

spectrumof area = (w)dwS = m zzo ∫ 1

Since the wave elevation is a random variable with a normal distribution and narrow band energy spectrum,

the same holds true for the heave motion. consequently, the normal distribution is valid for the elevations

and the Rayleigh distribution for the amplitudes.

em2

1=f(z) :function ondistributi Normal m2

z-

oo

2

π2

e_m

z=f(z) :function ondistributi Rayleigh m2

z-

oo

2

3

The probability of the exceedance of a certain value of the heave amplitude can be calculated as:

e =dz e_moz=a) ZP( m2

z-am2

z-aa o

2

o

2

∫∞f

4

The expected maximum heave amplitude can be calculated according to:

( ))N ln.29(+)N ln( *2mo = max Za -1/21/25

where: N = number of oscillations

For instance, in a six-hour storm with an average wave period of 10 seconds, the number of oscillations

would be N = 6 x 60 X 60/10 = 2160 and the

. m_4.07 = Za amplitude heave maximum the 0max 6

For quantities which do not have a linear response to wave motion, the above distribution function is not


Updated Dec. 1999

valid. Other means are necessary to define a probable-maximum design level.

3.4 Vessel Motion Definition

The movement of a ship, that is, the variation from some steady-state condition, has six degrees of freedom

as shown in Figure 22. A ship can move forward and backward (surge), side to side (sway) or up and down

(heave). It can also rotate about the longitudinal axis (roll), the transverse axis (pitch) and the vertical axis

(yaw).

For a ship in still water, a force producing surge, sway or yaw produces no restoring force. This is because

no change is made in the shape of the waterplane. A force producing roll or pitch alters the waterplane and

a restoring force is generated. Heave alters the displacement of a ship and force causing this is resisted.

3.5 Ship - Environment Interaction

Wind has the most common effect of reducing a vessel’s stability. The pressure of a bean wind is most

often presented as a maximum wind speed for positive stability. Since most classification societies have

incorporated some form of wind-heeling criterion, the class of a vessel will indicate, to some extent, the

resistance of the vessel to wind loading.

A moored vessel, such as a drilling rig, must resist the offsetting force of wind. In this case, the wind is

causing deleterious surge or sway which must be resisted by a mooring system. The ability of a vessel to

remain on location is usually measured in terms of the maximum wind which can be resisted. This load is

in conjunction with other environmental loads.

A head-on current has the direct effect of reducing a vessel’s speed. At other angles, the effect of current is

nearly direct. For a stationary vessel, current causes an offsetting force just as wind does. The ability of a

ship to resist current is usually expressed as the maximum velocity in which headway can be maintained or

station may be kept.

The response of a vessel to waves is a very complex problem. One wave passing a ship can effect

movement in all six degrees of freedom. For this reason, response is most often investigated by isolating

the motions as a result of regular waves.

If a ship is moving through a regular wave train, it will have some heave response, for example. This heave

will be different for different waves and ship speeds. Taking a moored ship, or one with no forward speed, a

relation can be found between wave period and vessel heave. This is usually plotted as heave of the ship

divided by wave height versus wave period as illustrated in Figure 23. This non-dimensional response

amplitude operator (RAO) curve is characteristic of the ship and can be compared to curves of other ships.

Similar curves can be developed for other degrees of freedom, speed of advance and vessel orientation.


Updated Dec. 1999

Response to irregular seas can also be predicted using wave energy spectra and the RAO curves. These

predictions are each good, then, for a specific:

Vessel speed

Vessel orientation

Vessel degree of freedom

Wave spectrum

The response of a ship to waves can be compared to many criteria. the maximum permitted response in

one of the degrees of motion may limit operations. On some vessels, acceleration must be kept below

certain levels. On the other hand, too slow a vessel response may cause prohibitive deck wetness.

Harmonic pitch response and flat bottom forward may combine to produce slamming. At the other end of

the ship, propeller emergence may be a problem. A speed reduction may be required due to one or all of

the above. The general term for the relation of a ship to its response in waves is seakeeping. There is good

seakeeping and bad seakeeping but no one number which can be calculated or measured to define it.

3.6 Drillship - Semisubmersible Comparisons

Because of its smaller waterplane area, a semi can carry less deck cargo at operating draft. As shown in

Figure 24, every ton of deck cargo must displace one ton of water. A semi must sink further to displace one

ton of water than a ship.

The semisubmersible first became popular as a drilling platform because of its motion characteristics.

Reduced roll, pitch and heave response to waves is due to the small waterplane area in relation to

displacement. The accelerating forces due to a wave passing are directly related to the waterplane area and

inversely proportional to displacement. Thus, a ship will be accelerated more in a small period wave train as

shown in Figure 25. The dip in the ship response curve indicates some harmonic tuning between the ship

length and the wave length at about 10 second period.


Updated Dec. 1999

4.0 MODEL TESTS

In view of the complex nature of forces and the often unpredictable behavior of marine vessels, model tests

are routinely carried out. These tests are scaled representations of the prototype.

The term “scale factor” refers to the relationship of the dimension of the prototype compared to the

dimension of the model. For example, if the prototype dimension is 60 times the dimension of the model,

the scale factor, designated by ?, is 60.

Normally the principal effects to be modeled in SPM model testing are forces due to gravity waves.

Therefore, Froude’s-law scaling is used for these model tests.

By Froude’s-law scaling for dynamic similitude, the following condition must be satisfied:

gLV =

gLV 2

m

2

p 7

where V = velocity

g = acceleration of gravity

L = characteristic length

p represents prototype

m represents model

Since, the acceleration of gravity is the same on the model as it is on the prototype, it follows that:

λ1/ = LpLm

= VpVm

2

8

Thus, the ratio of the scale velocities is ?-1/2. The ratio for time scale is also ?-1/2 since

( ) λλλ ‰-‰ = 1/ = VmVp

LpLm

= Lp/VpLm/Vm

= TpTm

9

Further, the ratio for forces is given by ?-3 since:

λ 3-3

3

3_=

LpLm

= ap x Lp x_(s.g.)p

am x m xL (s.g.)m =

FpFm

10

Both specific gravity and acceleration are the same for model and prototype.

Testing at as large a scale as practical is desirable because the accuracy of the results will be better. The


Updated Dec. 1999

accuracies of the modeled environments and the dimensions of the model will be proportionately better at a

larger scale. The ability to scale forces will also be better at a larger scale because certain phenomena

scale better by one scaling rule than by another, and the deviations are greater at smaller scales.

The effect of scale is more important in modeling small objects, such as cargo hoses, than it is in modeling

very large objects, such as tanker hulls. For example, above a critical Reynolds number, viscous-drag

coefficients are essentially independent of velocity, but small objects are more apt to have Reynolds

numbers below the critical range, and thus not scale properly.

Force and moment measurements are much more accurate at larger model scales. There is a practical

limit to how small and how accurate force transducers can be fabricated and calibrated. A one-Newton error

in a transducer produces a much larger error when scaled up from a small model. Furthermore, at small

scales the presence of a relatively large or heavy transducer can influence forces on the model or the

response of the model, and in turn produce errors in the results.

The model scale is limited, however, by facilities and cost. Limitations of available model test facilities and

equipment will govern more than cost. The length, width, and depth of the model basin, the capacity of the

wave generators, and the pumps and fans used to produce current and wind will limit the size of the model

which can be tested. There may also be a limiting relationship between the depth of water in the basin and

the height of wave or velocity of current which can be produced.

At a scale of 1/50, a model of 550,000 dwt tanker will be approximately 8.3m (27 ft) long and will weigh

approximately 50 kN (11,000 lbs) at loaded draft.

Several types of mechanisms are used to generate waves in the various model basins. The principal types

of wave generators are mechanical flaps or paddles, mechanical plungers, and pneumatic generators.

Wave generators generally are limited in their ability to produce short-period (high frequency) waves. For

example, if a wave generator cannot cycle faster than 1.5 hertz, it will not be able to produce waves with

periods shorter than about 5 seconds at a length scale factor of 60. This inability to produce the shorter

period components of wave spectra is common to all wave basins.


Updated Dec. 1999

When testing in survival conditions with cargo hoses, high-frequency response characteristics may be of

major concern. In such cases it will be necessary to match the high-frequency portion of the spectrum

more precisely. this may necessitate modeling the buoy and cargo hose system (without a tanker moored)

at a larger scale.

The most generally accepted method of modeling wind during SPM model testing is to produce the forces

and moments on the vessel by means of a generated wind field. A bank of fans is arranged perpendicular to

the desired wind direction at some distance from the model, such that a uniform wind field is developed over

the area occupied by the vessel at the SPM.

At the beginning of a test series in which wind will be modeled, a series of constrained-vessel wind-force

tests should be conducted to verify that Froude’s-law-scaled forces and moments are produced. The

longitudinal wind force, lateral wind force, and wind yaw moment are measured on a restrained vessel for a

number of different wind directions.

During the constrained tanker wind-force tests, the forces and moments that are measured are compared to

those forces and moments that have been determined in wind-tunnel model tests. The velocity of the wind

field generated by the bank of fans is adjusted until a reasonable match is obtained.

Another method of modeling wind forces is by several fans mounted on the vessel itself. Their velocity may

then be regulated by a yaw sensor coupled to a computer, such that they produce the desired forces on the

vessel according to Froude’s-law scaling.

In SPM model tests, current may be modeled according to Froude’s-law scaling. The predominant effects of

current on the vessel are form and viscous drag, and, in shallow water, a difference in water level across the

vessel due to blockage. The latter phenomenon is a gravity effect and is therefore accurately modeled by

Froude’s-law scaling. Viscous drag effects are minimal except at angles near bow-on to the current. The

form or pressure drag is of viscous origin, but appears in general to be independent of Reynolds number in

the range of interest in SPM tests with ship-shaped bodies.

The most realistic method of modeling current in SPM model tests is to generate a flow of water in the

model basin, with a velocity proportional to the prototype current using Froude’s-law scaling. Such a current

flow is usually produced by pumping water through a bank of inlet ducts along the side of the basin, and

returning water to the pumps through ducts on the opposite side of the basin.

The model, both vessel and mooring system, must represent the prototype in geometry and mass

distribution. Center of gravity, center of buoyancy, and natural periods should be accurately modeled so

that vessel dynamics and stability are identical to the prototype.

Since the elasticity of the mooring system is a crucial parameter, extreme care should be taken that the

load-elongation curve of nylon bow hawsers, chain weights, and chain elasticity are properly modeled.


Updated Dec. 1999

The quality of the instrumentation and data recording system is very important. The care taken in

accurately modeling the environment and the system is lost if the recorded forces and motions are distorted

by the instrumentation system.


Updated Dec. 1999

5.0 CLASSIFICATION SOCIETIES

5.1 Purpose

Classification societies are independent, objective, non-profit agencies which provide guidelines for the

design, construction and maintenance of sound vessels. A ship which is built to the requirements of the

rules of a classification society, under the inspection of the society’s surveyors, and with materials and

other components tested to society specifications is granted “classification” by formal action of the society’s

committee. This fact is then published in the society’s register and made public knowledge.

Classification establishes that an owner has used “due diligence”, it informs a shipper that he is using a

sound vessel, and it helps an underwriter determine the risks of insuring ship or cargo.

5.2 Societies

The following are recognized as major classification societies. While the specific rules of each differ, the

intent is the same.

American Bureau of Shipping

det Norske Veritas

Lloyd’s Register of Shipping

Bureau Veritas

Registrano Italiano Navale

Germanischer Lloyd

Nippon Kaiyi Kyokai

Russian Register of Shipping

5.3 Covered Items

Classification societies have rules addressed to the following:

Scantlings

Materials

Arrangements

Mooring equipment

Machinery

Controls

Workmanship

Stability


Updated Dec. 1999

5.4 Administration of Government Regulations

In addition to the application of their own rules which relate to the soundness of ships, classification

societies are used as the administering agent for regulations adopted by governments. These rules are

most often concerned with safety.

Date post:	06-Feb-2016
Category:	Documents
Upload:	adonis-saidler
View:	72 times
Download:	3 times

Petroleum Engineering Manual

Documents