Data Engineer Manual

1 of 53 Data Engineering

LOGGING SYSTEMS

AN INTRODUCTORY GUIDE TO DATA ENGINEERING

DATAENGINEERING

COURSENOTES

SG

NAME:

DATE:


LOGGING SYSTEMS

Data Engineering Course

CONTENTS

Introduction _________________________________________________________4

Formation Pressures and Hydrostatics____________________________________5

Equivalent mud weight____________________________________________________5

Problems caused by abnormal pressures _____________________________________6

Problems associated with excess overbalance _________________________________6

Problems associated with deficient overbalance _______________________________6

Problems associated with underbalance ______________________________________7

Overburden Gradients _________________________________________________8

Calculation of overburden _________________________________________________8

Formation Pressures _________________________________________________11

Pressure mechanisms ____________________________________________________11

Mechanisms ____________________________________________________________11

Tectonic movement ______________________________________________________12

Underpressure __________________________________________________________13

Drilling Exponent ___________________________________________________14

Calculation of overpressure values from dc __________________________________16

Pore pressure evaluation while drilling __________________________________18

Depth of Seal ___________________________________________________________18

Gas levels ______________________________________________________________21

Post drilling analysis _________________________________________________25

Pore pressure from sonic logs _____________________________________________25

Pore pressure from Density logs ___________________________________________28

Fracture Pressure ___________________________________________________29

Mechanisms ____________________________________________________________29

Leak off tests ___________________________________________________________29

Poissons Ratio (µ) _______________________________________________________33

Basic Drilling Fluid __________________________________________________35

Functions of drilling fluid_________________________________________________35

Definitions of some drilling fluid terms _____________________________________35

Clay chemistry__________________________________________________________36

Basic types of drilling fluids_______________________________________________37


LOGGING SYSTEMS

Drilling fluid additives ___________________________________________________37

Drilling Hydraulics __________________________________________________39

Flow regimes ___________________________________________________________40

Pressure losses and hydraulic horsepower ___________________________________41

Annular pressure losses and ECD __________________________________________41

Hole cleaning ___________________________________________________________41

Swab / Surge ___________________________________________________________41

Problems associated with swab / surge ______________________________________42

Well Control ________________________________________________________45

Procedures for killing a well ______________________________________________47

PWD and ECD - a quick guide _________________________________________49

Swab and Surge_________________________________________________________51

Hole cleaning ___________________________________________________________52


LOGGING SYSTEMS

Data Engineering Course

Introduction

Data Engineers are responsible for the safe and efficient operation of the surface acquisitionsystem. This includes monitoring rig activity, pore pressure and fracture gradient estimation,hydraulics optimisation, systems maintenance, reporting and supervising logging geologists.

Crossing the floor to the “dry” end requires a change of focus. Data engineers must knowwhat is happening on the rig at any time and what will be happening. They have much morecontact with rig and operator personnel and should be able to give advice as required.Morning meetings came into vogue in the early 1990s, but they really only served to formalisean existing forum. Many rig meetings are now video confrenced by satellite to the beach. Dataengineers should present a professional image and be prepared to be pragmatic.

The learning curve for a newly promoted data engineer is very steep. By this stage a seniorlogger should be able to run the logging unit on their own and have some idea of ADT work.

Hopefully this course will at best clarify this work or at worse introduce a different aspect ofLogging Systems’ activities.


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Formation Pressures and Hydrostatics

In ADT work, engineers use a variety of conversion factors and constants to calculate thevarious pressures and gradients (and to convert between them) involved in drilling wells. Themost common is 0.052.

A column of fresh water 1” square and 12” tall will exert a pressure of 0.433 psi/ft:

P = 62.4 lb/ft3 = 0.433 psi/ft 144 (in2 per ft2)

So, a fluid column of 8.33ppg (fresh water) exerts a pressure of 0.433psi/ft

∴ a column of any fluid of any density will exert a pressure of 0.433 = 0.0519 psi/ft per ppg 8.33

The metric equivalent (for use with specific gravity and metres) is 1.421

Equivalent mud weight

Very few operators use psi/ft to express pressure gradients. It is easier to deal with gradientsexpressed as equivalent mud weights. Pounds per gallon (ppg), specific gravity (sg), psi perthousand feet (pptf) are the most common. Shell are particularly keen on pptf, which isbasically psi/ft multiplied by 1000.

Calculating pressures and gradients is a frequent task in ADT work and the ability to work inthe various units involved is rapidly acquired. The basic equations are as follows:

To convert a mud weight to a pressure in psi :

ppg x 0.0519 x TVDft

sg x 1.421 x TVDm

To convert a pressure to a mud weight (EMW)

psi / TVDft / 0.052

psi / TVDm / 1.421

To convert a EMW to a gradient :

ppg x .052

sg x 1.421

NOTE : when calculating pressures using these equations always use True Vertical Depth.

Using the above, the ADT engineer can calculate the pressure exerted at a specific point inthe well. The use of these constants and formula soon become second nature.


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Problems caused by abnormal pressuresAn optimum mud weight is required to drill a hole in the most safe and efficient manner. Highmudweights lead to lost circulation, differential sticking, poor quality wireline / MWD logs andformation damage which has an adverse effect on any future production. Low mud weightslead to borehole instability kicks and problems with casing. Knowledge of the pore pressureregime in the well allows this optimum mud weight to be run. Ideally the mud weight should beclose to BUT above the formation pressure. The point where pore pressure equals the mudweight is called the balance point. When the mud weight is greater than the pore pressurethis is an overbalanced situation, while when mud weight is below the pore pressure this isunderbalanced.

Problems associated with excess overbalanceLost circulation - probably the commonest hole problem encountered. Lost circulation canrange from the slow seepage losses which can be treated with a little addition of LCM (LostCirculation Material) into the mud, to catastrophic losses which can be incurable and mayultimately lead to a kick due to loss of hydrostatic head. Mud is lost into natural fractures andfissures in the formation, but these may be opened or even generated by the mud weightexceeding the fracture pressure of the formation. Once these fractures have been opened it isnot always possible to close them by reducing the mud weight.

Formation damage - reservoir flushing and loss of porosity and permeability are alsoassociated with high overbalance. Borehole erosion and washouts may also occur leading topoor quality logs.

Differential sticking - thick filter cake may build up on the borehole increasing the area incontact with the drill string.

Low ROP - rock bits work by initiating and propagating fractures in the rock. If the differentialbetween the rock and the mud in the borehole is low, the rock chips fly off into the borehole. Ifthe differential is too high the chips will not fly off and the ROP will be reduced. This is calledthe chip hold down effect.

Problems associated with deficient overbalanceBorehole instability - Swelling clays can be caused by low overbalance, as can caving offormation into the borehole. These will manifest themselves as drag or fill.

Stuck pipe - borehole instability can cause the formations to swell or cavings to enter theborehole which can then stick the drillstring mechanically.

High gas levels - usually associated with lack of overbalance, especially if background andtrip gasses are high. Connection gas is also a good indicator of low overbalance.

Low overbalance is not necessarily a bad thing, but requires vigilance to prevent the situationmoving to the underbalanced case.


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Problems associated with underbalanceKicks - if porosity and permeability are encountered when in an underbalance condition, orunderbalance is created by swabbing, a kick may occur.

ADT work can allow this overbalance and therefore optimum mud weight to be achieved.Accurate and timely analysis of information can allow engineers to have a good handle on theformation pressure regime.


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Overburden Gradients

Much of the ADT and data engineers work in establishing the pressure regime of a wellinvolves the use of overburden gradients.

Overburden plays a pivotal role in the analysis of the pressure regime of a well. Overburden(for our purposes) is the cumulative pressure exerted by the, air, water and rock formationsabove the point of interest. Without an accurate value for the overburden, calculations relyingon overburden (such as pore and fracture pressure) will be correspondingly inaccurate.

As can be seen in the diagram (where the curve represents a gradient) air has a gradient of0.028ppg, sea water a gradient of 8.6ppg / 1.04 SG. These gradients are fairly constant for anoffshore well. Water depth can have a great effect on the overburden, especially in the morerecent deepwater projects west of Shetland.

On the other hand, the diagram shows that the gradient of the lithology increases with depthfollowing the Normal Compaction Trend. As compaction of the sediment occurs with depth,dewatering of the formation causes the density of that formation to increase. In deep ormature basins the density of the formations may reach a maximum as the diagenetic processruns it course.

Calculation of overburden

As noted above, overburden is a function of formation density. To calculate overburdenrequires an estimation of formation density. There is a variety of methods to acquire densitydata:

Bulk density - obtained by using drilled cuttings and a mud balance. Shale density can alsobe used, but involves potentially hazardous chemicals.

AIR GAP

OVERBURDEN GRADIENT

WATER

LITHOLOGY

DEPTH


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Sonic - using wireline data to calculate formationdensity from the wireline sonic log. Thetransit time in the rock is related to the density.

Density = 2.75-(2.15*(T-47)/(T+200))

This converts the transit time to a density by using known velocities for the lithology.

Density log - data from the wireline density log. These values, usually in sg, can be inputdirectly without any conversion

Of these the use of the density log is easiest, especially if you can get the data in ASCIIformat. Bulk and shale density can be suspect if hydration of the cuttings is occurring. Bulkand shale density do have the advantage of being used while drilling.

This data is acquired as an interval average, for example over 10 metres or 50 feet. If asciidata is available it can be imported to XL and an averaging macro run.

If ASCII data is unavailable and all you have is a log, eyeball an average for the interval. Takea piece of paper and copy the track scale. Use this as a scale for your estimation of theinterval average.

Having acquired your interval averages, input the values into a spread sheet. If using sonicyou will also need a column for the relevant lithology transit times. Refer to the mudlog for thelithology over the interval and input the relevant transit time.

Next, use the XL spreadsheet to produce an overburden data sheet similar to that shownbelow

OVERBURDEN DATA TABLEWell 399/12b-2 (Formation density from petrophysical log)

Depth Depth Interval Density Interval Cumulative Density EMW(mMD) (mTVD) (mTVD) (SG) Overburden (psi)Overburden (psi)Gradient (psi/m) (SG)

0 0 026 26 26 0.23 15 15 0.58 0.41

861 861 835 1.04 1234 1249 1.45 1.021450 1450 589 1.90 1590 2839 1.96 1.381460 1460 10 1.95 28 2867 1.96 1.38

In the above example the units are metric (metres, Specific Gravity or Grammes per cubiccentimetre), the density data is taken from the wireline log and is averaged over 10 metres.

The first interval (from RKB, 0m) to sea level (26m) is the airgap. This has a density of 0.23sg, multiply the density by 1.421 and multiply that by the interval producing an intervaloverburden of 15 psi. The next interval is from sea level (26m, to seabed (861m). This intervalcomprises 835m of seawater with a density of 1.04 sg with the interval overburden being 1234psi. These interval overburden values are added together to produce an cumulativeoverburden with a value of 1249 psi.

Since logs were not run until 1450m and there were no surface returns, there is an informationgap from 861m to 1450m. An estimation of the formation density is used to calculate themissing interval. In this case an estimated density of 1.9 sg over an interval of 589m gives aninterval overburden of 1590 psi. This is added to the cumulative to produce a new cumulativeoverburden of 2839 psi.


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From 1450 m the wireline density data is available and this is input into column 4 of the table.The interval overburden and cumulative overburden are calculated for each 10m interval forthe entire section or well.

Up to this point all the overburden data is expressed as a pressure in psi. For our purposesthe overburden should be expressed as a Gradient. Column 7 of the table converts cumulativeoverburden (in psi) to a density gradient in psi per metre (psi/m) by dividing the cumulativeoverburden by the vertical depth. The last stage, in column 8 is to convert the density gradientto an equivalent mud weight in sg by dividing the gradient in psi/m by 1.421. This is the dataused in pressure evaluation work and imported into the INSITE database for use in logs.


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Formation Pressures

Work on formation pressures by Terzaghi and Peck established the following relationship:

S = σ + P

Where : S is the overburden pressureP is the pore pressure

σ is the formation matrix stress

This relationship is the foundation on which all pressure engineering is built.

During normal compaction, water in the pore space will be squeezed out and the rock will besupported by the matrix. If the fluid is unable to escape, the rock will become supported by thefluid in the pore space. The overlying rock will cause this pore fluid to become overpressured.

Matrix stress is the difference between the pore pressure and the overburden pressure.

Under normal compaction the porosity of the formations should decrease and the bulk densityshould increase with depth. Plotting these on semi-logarithmic graph paper produces astraight line. This line is called the Normal Compaction Trend. If shale density is plotted anypoints on the Normal Compaction Trend will be normally pressured.

Pressure mechanisms

Normal formation pressure is expressed as :

P = ρ x g x D

Where ρ = average density of the fluidg = gravitational accelerationD = height of the column

e.g. fresh water would give a pressure gradient of 0.433psi/ft. In most drilling environmentsthe salinity of the pore fluid ensures that normal pressure gradients will rarely be equal to thatof fresh water. Normal pressure gradients (for the sake of overpressure detection) vary fromarea to area, e.g. the North Sea has a normal gradient of 0.452psi/ft whereas the Gulf Coasthas a typical normal gradient of 0.465psi/ft.

Underpressure is any formation pressure below the recognised normal gradient of the area.

Overpressure development relies on the inhibition of fluid flow, both laterally and vertically,within the rock column. This seal prevents the dewatering sediments undergo as they arecompacted and buried. Generation of hydrocarbons may also produce overpressure.

Mechanisms

Hydrocarbon reservoirs - Oil and gas bearing formations may be overpressured throughbeing in communication with the deepest formations of the sequence.

Undercompaction - sometimes called sedimentary loading. Low permeability and rapiddeposition restricts the escape of pore fluid from argillaceous sediments thus preventing the


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establishment of hydrostatic equilibrium. These mechanisms usually result in overpressuredshales such as those found in the tertiary of the Central North Sea. The rate of overpressureincrease within these shale sequences depends on the integrity of the seal. Some sequencescontain thin limestones that act as a perfect seal, producing very rapid increases inoverpressure. Sequences with imperfect seals are characterised by a gradual increase inoverpressure with depth, possibly over hundreds of metres.

Another form of undercompaction is tectonic loading. If a thrust fault moves rock over anuncompacted sequence, an effect similar to sedimentary loading my generate overpressure.

Aquifers - While not strictly geopressure, the overpressure in this case is the result of thehydrostatic effect of the water column.

Aquifer

Tectonic movement

Faulting - allows communication between deeper, pressured formations and shallowformations. If these fluids cannot escape to the surface, overpressure will result. Overpressurecan also be produced if a permeable zone is faulted against an impermeable zone, thussealing the permeable zone and preventing de-watering. Associated uplift may also causepressure

Faulting and or uplift

Uplift - if a formation, which is normally compacted and pressured at depth, is uplifted, theoriginal formation pressure may be maintained. Any uplift of a sequence usually results insome erosion of the overlying formations (overburden). For the same degree of movement,


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uplift from shallower depths produces a greater increase in overpressure than from muchdeeper.

Uplift

Aquathermal pressuring - a formation that is totally isolated will generate overpressure as itis buried as a result of the geothermal gradient.

Charged Sands - a shallow sand sequence can be charged up by gas migrating from adeeper formation. This will normally be encountered in areas where wells drilled previouslyhave suffered subsurface blow out or have been poorly plugged and abandoned.

Charged formation

Clay diagenisis - Montmorillonite alters to Illite during diagenisis. The interlayer bound waterin Montmorillonite becomes free and is released into the pore space, causing over pressure.

Salt domes - the plastic movement of salt formations can cause pressure anomalies due tothe faulting and folding accompanying diapirism. In addition, formations within the salt such asdolomites may become overpressured due to uplift within the salt, e.g. the Plattendolomit. Saltmay also seal clay formations, preventing dewatering.

Underpressure

Also referred to as subnormal pressures due to the pressure gradients being less that 0.433psi/ft. The main form of underpressure encountered in the North Sea area is caused bydepletion of reservoirs due to production. The gas reservoirs of the southern North Sea can bedepleted to 6ppg EMW.


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Drilling Exponent

While indicators like gas, drag or fill allow the ADT engineer to suggest the presence ofoverpressure, an operator needs to know how to restore an effective overbalance. Thisrequires quantitative evaluation to produce an estimate of the overpressure as an equivalentmud weight. In short the operator wants to know how much to increase the mud weight.

This would normally happen while drilling, so drilling parameters supply the data required. Thedata is used in a drilling model, which attempts normalise all the parameters to produce afigure independent of parameter variations, but generating a value that represents theformation characteristics. There are a few drilling models, Modified Log Normalised Drill ratebeing Sperry-Sun developed, Instantaneous Drilling Evaluation Log was developed by Anadriland Sigmalog, developed by AGIP abd Geoservice. MLNDR and Sigmalog suffer from beingarea specific (MLNDR to the Gulf of Mexico, Sigmalog to the Po valley). The commonest andmost understood drilling model is d exponent.

Various workers had looked at the problem of using drilling data to generate pore pressurevalues, but until 1966 the results were unsatisfactory. Jordan and Shirley derived an earlierdrill rate equation to produce an equation for drillability, d, or the d exponent.

The d exponent varies inversely with ROP, but will increase with depth in a normallycompacted argilaceous formation.

The next step was to modify the equation to incorporate mud weight changes, using thenormal pore pressure divided by ECD (Effective Circulating Density). This is called theCorrected (or Modified) d exponent, dc.

The days of hand calculating d exponents are long gone, so suffice to say that dc is plotted onsemilog paper against TVD and allows the ADT engineer to calculate pore pressures basedon deviation from the normal compaction trend.

Plot of dC


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As can be seen in the plot above, plots of dc require careful interpretation. Having to rely onpicking up deviations from the trend line is fraught with problems. The initial problem is whereto place the trend line. Dc is also sensitive to changes in formation, hole size and bit type.Shales and claystones give the most reliable dC, so the trendline is placed so that it interceptsas many “shale points” as possible. Normal compaction should increase to the right, while thedeviations that indicate overpressure should be seen as a “cut back” to the left. Dc exponent isoften criticised for inaccuracy and its reputation is not enhanced by poor interpretation. Dc

should only be used in conjunction with other indicators.

Dc plot showing the information required for accurate interpretation

There are many debates about the movement of trend lines. In the case above had the trendline not been moved to the left for the 12 1/4” hole the calculated pore pressures would havebeen wildly inaccurate. Also visible in the plot above is the effect of using PDC bits, which alsomove the dc to the left. As dC is in effect an indicator of drillability, sandy formations may drillfaster making dc shift to the left while hard limestones shift it to the right. A fining up sequencewill generate a dc trace that appears to cut back, but is in fact due to the formation becomingmore arenaceous. The dc exponent is unreliable when coring.

Most important feature of the above plot is that the clay section where the PDC bit was run isoverpressured. The dc can be seen cutting back to the left before entering the limestonesequence.

Bit dulling causes the dc to trend to the right, due to decrease in ROP. This may mask a cutback due to overpressure, but is only a pronblem towards the end of the run.

Thin carbonates will effect the trend, but can also seal an overpressured zone. Marls causethe trend to shift to the right, which can give the impression that any overpressure is lower.

In summary, the dc exponent plot shows where overpressure probably is, but must beinterpreted with care (especially when shifting trend lines) and with reference to otherparameters.


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Calculation of overpressure values from dc

The commonest method of calculating pore pressure while drilling is the Eaton Equation,using the corrected d exponent (dc).

p = S - [ (S - pn) x (dco / dcn) 1.2

]

Where p = Pore Pressure

S = Overburden

pn = Normal Pore Pressure

dco = Observed dc exponent

dcn = Normal dc exponent

dc exponent v depth plot

0

5000

10000

Depth

Ft

Normal

Compaction

Trend

AbnormallyPressured Shale

TVD

1.00.5Dc Exponent

Dco = 1.0Dcn = 1.25

1.2

Using the data from the dc plot:

p = Calculated Pore Pressure

S = Overburden = 19 ppg


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pn = Normal Pore Pressure = 8.7 ppg

dcn = Normal Dc exponent = 1.25

dco = Observed dc exponent = 1.0

p = 19 - [ (19 - 8.7) x (1.0 / 1.25)1.2

]p = 19 - (10.3 x 0.765)

p = 19 - 7.879

p = 11.12 ppg


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Pore pressure evaluation while drilling

There are other methods of estimating formation pressure while drilling in addition to dc. Theydo, however, depend on samples of formation being available.

Bulk density - Cuttings are washed and placed in a Baroid balance until the balance reads8.33ppg / 1.0sg. Top up with fresh water (stirring to expel air) and replace cap. After wiping offany excess water, reweigh and take the reading from the scale. Use the reading in therelevant formula.

1 8.33

sg = ------------------------ ppg = -------------------------------

2 - Final Weight 16.66 - Final Weight

Values tend to be lower than shale density due to absorption of drilling fluid and the washingwater by hydroturgid shales, but trends can be seen. Useful in argillaceous rocks. Watch fordecrease in trend, this is indicative of overpressure.

Shale density - a graduated column filled with variable density fluid and 4 - 5 glass beads ofdifferent (known) density is used to test the density of shale fragments. A calibration chart isdrawn with density against the graduations on the column. Shale fragments are dropped in thecolumn and the point where they stop is read off and checked against the calibration chart.

Again, the density is plotted against depth and any deviation from the trend may indicateoverpressure.

Shale factor - also known as the Methylene Blue TesT (MBT) test. Measures the cuttings’Cation Exchange Capacity. As diagenesis proceeds, the Montmorillonite in the sedimentsconverts to Illite, so the amount of Montmorillonite should decrease with depth. Overpressuredzones are more likely to have increased Montmorillonite due to normal dewatering not havingtaken place and the pore fluid supports more of the overburden. Diagenesis, being pressurerelated, does not occur to the same extent due to this fluid supported condition, so the ratio ofMontmorillonite to Illite in a given formation will increase. Montmorillonite has a higher CationExchange Capacity than Illite, so the higher the CEC, the more Montmorillonite. Shale factorshould decrease with depth, following a normal compaction trend. Deviations from the normalcompaction trend should indicate overpressured zones.

Calculating pore pressure from the above involves plotting the data against depth, identifyingthe normal compaction trend and any deviations from that trend. The method used tocalculate a formation pressure is called the Depth of Seal method.

Depth of SealMay be used with formation density, seismic velocity, formation resistivity, interval transit time,Dc Exponent or shale factor.

Based on the density of an overpressured shale at the depth of interest being the same as thedensity at the "depth of seal" on the normal compaction trend.

As a result of this relationship, the Matrix Stress at these depths will be the same.


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Formula S = σ + P

where S = Overburden

σ = Matrix Stress

P = Pore Pressure

EXAMPLE

This example uses a plot of shale density.

To calculate the Pore Pressure at 5400ft

Depth of seal (ds) 1400ft

Overburden at 1400ft S(ds) 0.68 psi/ft


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Overburden information from the well overburden table or offset data

Pore pressure at 1400ft P(ds) = normal 0.45 psi/ft

Depth of interest (di) = 5400ft

Overburden at 5400ft S(di)= 0.83 psi/ft

Using the relationship S = σ + P

σ = S(ds) - P(ds)

σ = 0.68 - 0.45 psi/ft

σ = 0.23 psi/ft

Since all pressure variables should be in units of absolute pressure, they must all beconverted to psi.

Calculate the matrix stress s at depth of seal (ds)

σ psi = σ x (ds)ft

σ psi = 0.23psi/ft x 1400ft

σ psi = 322psi

Calculate S(di)the overburden at depth of interest,

S(di) = S(di) psi/ft x (di)ft = S(di) psi

S(di) = 0.83 psi/ft x 5400ft = 4482 psi

To calculate the pore pressure at 5400ft, P(di), use:

P(di) = S(di) - σ

P(di) = 4482 psi - 322 psi

P(di) = 4160 psi

Convert to ppg =

4160 psi

0.052 x 400ft

= 14.8ppg

Calculated Pore Pressure at 5400ft = 14.8ppg


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Other Pore Pressure Indicators

Gas levels, drag, fill, temperature, cavings and torque can indicate the presence ofoverpressured formations. They can been used qualitatively to lend support to informationobtained from quantitative methods such as dc.

Gas levels

After dc exponent, gas is probably the best indication that an overpressured formation is beingpenetrated. Although affected by lithology and ROP, gas remains a good qualitative indicator.

The diagram above shows the effect of increasing pore pressure on gas levels

Background gas - The amount of gas in the mudstream is dependent on the ROP,amount of gas in the drilled formation and the pressure differential in the borehole. As thedifferential between pore pressure and mud hydrostatic is reduced by increasing porepressure, background gas gradually increases.

Connection gas - as the differential approaches balance, additional gas can beintroduced to the well bore by the action of pipe movement at connections causing swabpressures. Connection gas appears as sharp peaks above the drilling background gas level.The peaks will appear at bottoms up from the connection. Connection gas can be used toquantify the pore pressure by using the swab/surge application to calculate swab pressures.NB connection gas is reported as a peak above background.


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Snapshot showing connection gas

Trip gas - the size and arrival time of trip gas can give an idea of the downhole environment.Although also caused by the swab action of the pipe, trip gas is thought to be caused by poorfilter cake formation, due to low overbalance.

Non-drilling background gas - a very useful tool as it indicates the state of the holewhen the bit is off bottom and circulating. On high pressure / High temperature wells it is goodpractice to circulate off bottom to establish a non-drilling background. As this is unaffected bydrilling effects, variations in NDB can indicate changes down hole.

Cavings - as balance is approached the confining pressure on the drilled formation may bereduced enough to allow fragments of rock to slough off and cave into the borehole. Thecavings will be carried to the surface by the mud, but if too large to be lifted, will remain in thehole to cause further problems. When examined, pressure cavings are normally larger thandrilled cuttings, splintery and curved. Note some formations may react with mud to producesimilar cavings e.g. the Kimmeridge Clay.

Drag on connections - indicates that the borehole is unstable and the shale behavingplastically. As overpressured (undercompacted) shales can behave in a plastic manner theborehole wall encroaches on the bit and stablisers, showing as drag when the string is pickedup. Pressure cavings can also enter the hole and accumulate around the bit. Note - in highangle directional holes drag is normal, so it is unreliable as a pore pressure indicator.

Torque - As with drag, torque is caused by the borehole encroaching on the drilling tools.Again torque is unreliable in high angle holes.

Fill - on going back on bottom after a connection cavings that have accumulated at thebottom of the hole have to be "drilled out". The caving process may be aggravated by the lackof additional overbalance when the pumps are shut down.


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The snapshot above shows the effect of hole fill after a short trip.

Temperature - overpressured zones are characterised by having a increased thermalgradient. Flow line temperature and ∆T (temp out - temp in) are normally plotted and shouldgive an indication that an overpressured zone is being approached. Entering an overpressuredzone will normally be associated with an increase in flow line temperature.

Plot showing temperature against depth when drilling into an overpressured zone. Note howthe temperature gradient decreases in the cap rock.


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Drilling the cap rock above the zone may show a decrease in flowline temperature due to itshigher thermal conductivity, but as the undercompacted zone is entered, flow line temp shouldincrease. Temperature readings can be affected by many surface factors such as mudadditions or riser length, so much so that in some cases it is useless.


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Post drilling analysis

Wireline logs allow the ADT to check the pore pressure values obtained while drilling. Themain parameters used are Sonic, Density and Resistivity. Direct formation pressure readingscan be obtained from RFT (Repeat Formation Tester) tools, which measure the pressure inthe formation by clamping a pressure tool to the borehole wall. RFTs require some porosityand permeability to obtain good readings, so are not suitable for measuring presures fromclaystones.

Pore pressure from sonic logsPost drilling pore pressure analysis can be done using sonic logs, again using the EatonEquation.

Sonic transit time, ∆T, will decrease with depth as the density of the formation increases dueto reduction in porosity. Sonic is plotted against depth on semilog paper and a normalcompaction trend identified. Deviations from the trend may be due to overpressured formation.

p = S - (S - pn) x ( ∆Tn / ∆To)3.0


S = Overburden


∆Tn = Normal Sonic ∆T

∆To = Observed Sonic ∆T

Pressure variables used in these calculations should be expressed as gradients (psi/ft)

0

5000

10000

Depth

Ft

Normal

Compaction

Trend

80 100 200Sonic Velocity ( sec/ft)µ

∆ Tn

∆ To

∆ To∆ TnAbnormallyPressured Shale

= 138

= 191

Using the data from the sonic plot:



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S = Overburden = 0.68 psi/ft

pn = Normal Pore Pressure = 0.452 psi/ft

∆Tn =Normal Sonic ∆T = 138 usec/ft

∆To = Observed Sonic ∆T = 191 usec/ft

p = 0.68 - (0.68 - 0.452) x ( 138 / 191 )3.0

p = 0.68 - (0.228 x 0.377)

p = 0.59 psi/ft

p = 0.59 / 0.052 ppg

p = 11.42 ppg


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Pore pressure from resistivity logs

Post drilling pore pressure analysis can be done using resistivity logs, again using the EatonEquation. If MWD resistiivity tools are being run it is also possible to calculate the porepressure while drilling, in a similar manner to that employed for dc.

Deep resistivity is the most relevant for pore pressure detection as it will ideally be readinguninvaded formation.

Resistivity should increase with depth through a normally compacted shale section, due to thedecrease in the volume of pore fluid. Deviations from the normal trend may be due toundercompacted sediments, but be aware that resistivity changes with the salinity of the porefluid.

p = S - (S - pn) x ( Rn / Ro)1.2


S = Overburden


Rn = Normal Resistivity

Ro = Observed Resistivity

Pressure variables used in these calculations should be expressed as gradients (psi/ft)


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S = Overburden = 0.68 psi/ft

pn = Normal Pore Pressure = 0.452 psi/ft

Rn =Normal Resistivity = 1.1 Ohm/m

Ro = Observed Resistivity = 0.6 Ohm/m

p = 0.68 - (0.68 - 0.452) x ( 0.6 / 1.1 )1.2

p = 0.68 - (0.228 x 0.438)

p = 0.59 psi/ft

p = 0.59 / 0.052 ppg

p = 11.15 ppg

Pore pressure from Density logs

Uses the same depth of seal method as described for “while drilling”, but with wireline densitydata.


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Fracture Pressure

Fracture pressure determines the maximum mud weight which can be run in a particular holesection. While high mud weights are used to control overpressured zones, severe problemscan be encountered if the mud weight, or rather its hydrostatic pressure, exceeds the fracturepressure of the formation. Accurate knowledge of the formation fracture pressure is necessaryto prevent problems such as lost circulation or subsurface blow outs.

MechanismsApplying pressure to a formation will initiate fractures along the line of least resistance withinthe rock. To propagate these fractures the pressure must be greater than that of the leastprincipal stress. Fractures will propagate normal to the direction of least principal stress. Thisdirection can be ascertained by looking at the region’s faults. Normal faults indicate the leastprincipal stress is horizontal. Reverse faults indicate least principal stress is vertical.Transcurrent faults, although indicating horizontal, means that the stress is higher than fornormal faults but insufficient to cause reverse faulting.

Leak off testsLOTs are performed to establish the formation breakdown gradient after a casing string hasbeen set. After drilling out the casing tools and a few metres of new formation the hole will becirculated clean and the annular preventer closed. Using the cement pump, the pressure isincreased by pumping in increments until leak off is attained.

Leak off test graph

To calculate the leak off as an EMW, convert the mud weight to a hydrostatic pressure, addthe surface pressure, then convert back to a mud weight.


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Casing is normally set in a competent formation like a claystone and the LOT is usuallyperformed in a similar formation. Unfortunately if the formation changes to a less competentlithology such as a sandstone, the maximum allowable mudweight (obtained from the LOT) isno longer valid. In order to maintain borehole integrity the ADT engineer calculates fracturegradient while the hole is being drilled. This requires a model which can be updated withdepth.

Daines Fracture Gradient

The Daines method is the most widely used technique for the estimation of fracture gradients.Its use is recommended by most operators and is specified by BP on all of their wells. Oursystems offshore are configured to produce fracture gradients using this method.

Fracture gradients can be estimated by employing the Daines technique which incorporatesthe use of a tectonic stress which is either known for a region or is calculated from Leak OffTest values. Tectonic stresses are calculated at each Leak Off Test using the Dainesrelationship:

Tectonic Stress ( T ) = F - [ (S-P) x ( µ )+ P ]

-µ

Where,

S (sg emw) = Overburden pressure

P (sg emw) = Pore pressure

F (sg emw) = Fracture pressure

µ = Poissons Ratio.

Poissons ratio (µ) is a value between 0 and 1 that attempts to reflect the relationship betweenelasticity and rigidity of different lithologies. There is a predefined list of figures available thathave been collated from the work of various authors, notably Wuerker (1961) and Daines(1982). Fracture gradients can then be calculated at regular depth intervals, inputtingappropriate values for Poisson's Ratio at each lithology change. As each leak off test/formation integrity test is performed the equation above can be rearranged to give :-

Fracture Gradient ( F ) = T + [ (S-P) x ( µ ) + P ]

-µ

Daines’ method uses the actual formation fracture pressure as a basis for further calculationsas the well deepens. This fracture pressure is the Leak Off Test Pressure gradient. Byknowing the formation at the test depth (from the log) it is possible to look up the Poisson’sratio of that formation. Since the overburden gradient and the formation pressure is known,the tectonic stress ratio for the well can be calculated.

The tectonic stress ratio is then used to calculate fracture pressures as drilling proceeds, onlyrequiring the Poisson’s ratio to be changed. Good geological control is required for Daines towork as advertised. As it is the rock matrix which is involved in the fracturing, attention should


LOGGING SYSTEMS

be paid to any matrix or cement in the formation. The Poisssons ratio should be selected onthis basis.

One feature of the Daines method is that it does require a Leak Off Test. Many operators onlyconduct formation integrity tests. An FIT is conducted to ensure that the formation will be ableto hold a specific pressure without breaking down. As a result this FIT does not represent thetrue fracture properties of the formation at that depth. This can produce spurious results whenthe FIT values are applied to fracture gradient prediction. The diagram below shows the effectof using FIT data compared with LOT data. Engineers should be aware of this.

AIR GAP

FRACTURE GRADIENT

DEPTH

WATER

L

I

T

H

O

L

LOT = 1.74 SG

30” CSG

20” CSG *FIT =1.56SG


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Calculation of fracture gradients in practice

As in the case of overburden, the fracture gradient calculations are best done on aspreadsheet. The first step is to calculate the tectonic stress ratio from the leak off data. Thisuses the overburden, pore pressure gradient and the Poisson’s Ratio at the leak offdepth.

Having calculated the tectonic stress ratio, it is used as the reference cell for the rest of thedrilled interval. Set up the next section of the spreadsheet using the same depth interval asthe overburden. Copy the overburden gradient data into the fracture sheet as column 2 , andinput the pore pressure in the next column. The fourth column calculates the matrix stresswhich is overburden minus the pore pressure. Column five contains the Poisson’s ratio, and isinput manually depending on the lithology. Column 6 contains the µ ratio that is the Poissonsratio divided by 1 minus Poisson’s ratio.

The horizontal stress is calculated in column 7 and is the matrix stress multiplied by the µratio. Column 8 calculates the tectonic stress, which is the tectonic stress ratio multiplied bythe matrix stress. the final column calculates the fracture gradient using the Daines equation.

The fracture gradient data can then be used for reports and plots.

Daines fracture gradient spreadsheet

FIRST LEAK OFF TEST DATA LOT DEPTH: 1698 mMDLOT Overburden Pore Press. Matrix Stress Daines Ratio Horiz. Tectonic Tectonic/Matrix

sg S P S-P µ µ/(1− µ) Stress Stress Stress Ratio

1.31 1.48 1.04 0.44 0.17 0.20 0.09 0.18 0.41

(Const. for the w ell)

GIVEN: F = P + ( S - P ) ( µ / 1− µ ) + σ w here σ = Tectonic Stress

Well 399/12b-2Depth Overburden Pore Press. Matrix µ µ Horiz. Tectonic Fracture

m S (sg) P (sg) S-P Ratio Stress Stress Pressure

1710 1.39 1.04 0.35 0.17 0.20 0.07 0.14 1.251720 1.39 1.04 0.35 0.17 0.20 0.07 0.14 1.261730 1.40 1.04 0.36 0.17 0.20 0.07 0.15 1.261740 1.41 1.04 0.37 0.17 0.20 0.07 0.15 1.261750 1.41 1.04 0.37 0.17 0.20 0.08 0.15 1.27


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Poissons Ratio (µ)

Clay (v. wet) 0.5

Clay 0.17

Coal 0.19

Conglomerate 0.2

Dolomite 0.21

Greywacke course 0.07

fine 0.23

medium 0.24

Limestone fine micritic 0.28

medium calcarenitic 0.31

porous 0.2

stylolitic 0.27

fossiliferous 0.09

bedded fossils 0.17

shaley 0.17

Sandstones coarse 0.05

coarse, w cemented 0.01

fine 0.03

very fine 0.04

medium 0.06

poorly sorted, clayey 0.024

fossiliferous 0.01

Shale calcareous (<50% CaCO3 0.14

dolomitic 0.28

siliceous 0.12


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silty (<70% silt) 0.17

sandy (<70% sand) 0.12

kerogenous 0.25

Siltstone 0.08

Slate non calc mudstone 0.13

Tuff Glass 0.34


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Basic Drilling Fluid

What follows is a basic introduction to drilling fluids, taken from the ADT manual. It covers thefundamental uses, properties and types of mud (water based mainly) and is by no meansmeant to be comprehensive or definitve. For further, and more current information, ask themud engineer.

Functions of drilling fluid

• Remove cuttings from the hole.

• Suspend cuttings during trips.

• Allow cuttings to settle in the surface system

• Form wall cake on the formation

• Prevent caving of the formation

• Control formation pressures

• Control corrosion of drilling tools

• Lubricate and Cool Bit

Definitions of some drilling fluid terms

plastic viscosity (PV) - plastic viscosity is a measure of the flow resistance of fluids. PV isthe difference between the θ600 and θ300 readings. PV is related to the number and size ofthe solid particles in the drilling fluid as well as the viscosity of the fluid phase.

Yield Point (YP) - a measure of the attractive forces existing between particles and betweenparticles and fluid. YP is the θ300 reading minus the PV.

Gel Strength (GELS) - measures the attractive forces in a mud related to time. Normallymeasured at 10 seconds and 10 minutes, gel strength represents an expression of thixotropy.

PV, YP and gel strength are generated by using a rheometer, and the values obtained areused in hydraulics calculations.

Apparent Viscosity (VIS) - the time in seconds for a quart of mud to drain from a Marshfunnel. Vis is a rough guide to mud properties much loved by American toolpushers, but notused in hydraulics calculations. Its main function is to exend the time the shaker hand spendson the PA.

Filtration (fluid loss) - is a measure of the amount and rate at which mud loses its liquid to theformation. This is measured using a standard filter press at 100 psi, and is reported inml/30mins. The higher the fluid loss, the thicker the filter cake and the greater the dehydrationof the mud.

Filter Cake - this is the thickness of the residue expressed in 32nds or mm. It is invariablyequal to 2.


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Clay chemistry

Most water based muds are generally composed of clays. The principal clay is Bentonite,which is Sodium or Calcium Montmorillonite.

When added to water, or affected by the ions in water, the following reactions will occur:

Dispersion - the clay platelets separate, the Na+ goes into solution, leaving a net negativecharge on the faces of the clay platelets. The resultant repelling forces disperse the platelets.

Aggregation - the opposite of dispersion, where the platelets remain or become clumpedtogether.

Flocculation - edge-to-edge or edge-to-face clumping of platelets when attractive forcespredominate.

Deflocculation - results when the attractive forces between edge-to-edge or edge-to-face areneutralised.

Causes, description and remedies for clay behaviour

Dispersion - results when dry clay aggregates are added to fresh water. Caustic Soda isusually added to assist in disaggregation.

Properties Of Dispersion - attractive forces minimal, PV is high to very high, YP is relativelylow and gels are low. Filtration rate is low.

Flocculation - in the presence of salt or divalent ions, eg when drilling halite or anhydrite withfresh water mud, flocculation and aggregation of clay platelets results.

Properties Of Flocculation - attractive forces at a maximum, PV is high,YP - is very high,gels are high, filtration rate very high.

WATER

CAUSTIC Na+

Na+

Na+OH-

OH-

OH-

Na+

Na+

Na+OH-

OH-

OH-

NaCl

CaSO4 Na+

Na+Ca++

Ca++ Ca++


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Basic types of drilling fluids

Muds range from spud muds to the latest high technology oil free muds. They differ incomposition depending on the conditions they will be used in. The wrong mud in the wrongformation can lead to serious problems.

Spud Mud / Native Mud - uses bentonite or native clays from drilled formations, has little orno chemical treatment and has no resistance to contamination.

Organic Thinned Freshwater Mud - contains bentonite for viscosity lignin, tannin orlignosulphanate for gel control, Carboxymethylcellulose (CMC) for filtrate control and NaOHfor pH control. These muds have fair resistnce to contamination.

Lime Muds - inhibited freshwater mud using Ca(OH)2 to inhibit shale hydration, organicthinners and NaOH to control pH. These muds have good resistance to contamination.

Gyp Muds - inhibited freshwater muds containing Gypsum to inhibit shale hydration.Lignosulphanate thinners and filtration agents are used, with NaOH used to control pH. Thesemuds have good resistance to Anhydrite and salt contamination.

KCl Polymer Muds - Use KCl salts to inhibit shale hydration with cellulosic polymers forviscosity. Bentonite and CMC can be used to control fluid loss, while NaOH is used for pHcontrol. These muds have fair resistance to salt contamination.

Low Solids Muds - used extended or beneficiated bentonite to reduce the concentration ofbentonite. CMC is used for filtration control, with NaOH for pH. These muds have fairresistance to contamination due to the lower reactive solids content.

Salt Water Muds - built using sea or other salty water. bentonite for viscosity, CMC to controlfluid loss, lignosulphanate or lignins for thinning and NaOH for pH control.

Saturated Salt Muds - uses NaCl to saturate the mud for drilling Halite sections. ZEOGEL, abetonite for use in salt muds is used as a viscosifier, starches for fluid loss, lignosulphanatefor thinning and NaOH for pH control. A common type you may encounter is Thixal.

Oil Based Muds - use refined oils for the fluid phase with emulsifiers added to form anemulsion with the water phase. CaCl2 is added to the water phase,

Drilling fluid additives

Additives are used to alter the chemical and physical characteristics of the mud producing thedesired effect on the drilled formation

Weighting Agents - to control formation pressures a weighting agent like barite is used.barite has a specific gravity of 4.3. Other weighting agents include: Calcium Carbonate,Calcium Chloride, Galena and Haematite.

Thinning Agents - thinners reduce the attractive forces between clay particles in the mud,resulting in reductions in YP, gel strength and vis. Organic thinners include lignins, tannins andlignosulphanates, although the toxicity of some thinners has led to the development of others.

Filtration Control Agents - these absorb and hold water in the mud and form a filter cake,which reduces the rate of water loss. These include CMC, starches and polysacharides.


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pH control - Caustic Soda (NaOH) is added to mud, keeping the pH above 8 to aid thesolubility of thinning agents. Caustic Soda also gives better yield to bentonite.

LCM - (Lost Circulation Material). This may consist of varying types and sizes of particulatematter. Often you may see Baracarb, (Calcium Carbonate of known ‘mesh’ size) and “NutPlug” (literally ground-up walnut shells). There are however, many differing types of LCM,each useful in its own particular situation.

Other Additives - Soda Ash to treat Ca++ contamination, Bicarbonate of Soda to treatcement contamination. Defoamers and corrosion inhibitors may also be added


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Drilling HydraulicsMoving mud around the circulating system requires a certain amount of pressure input at thepumps. As the mud moves around the system, friction from the pipe work, drill string, jets andannulus dissipates this pressure. Hydraulics analysis allows the ADT engineer to check wherethese pressure losses occur and optimise them. By optimising hydraulics, the drilling actioncan be made more efficient.

System pressure loss - The input pressure (which is visible as the standpipe pressure) is thesum of the losses in all the sections of the system. The main areas of loss are: surface lines,drill string, bit and the annulus. The pressure loss across the bit is the most important, it beingdesirable to expend as much energy as possible at the bit, thus increasing the efficiency of thedrilling action.

Factors affecting hydraulics - the size of the system components and the properties of themuds have the most effect on hydraulics.

Fluid behavior models

Hydraulics analysis requires some knowledge of fluid behavior and some form of model isnecessary. The simplest is that of a Newtonian fluid : Water

Newtonian fluid behavior

Mud, being a suspension of material in water or oil, does not behave as a Newtonian fluid, soanother model was developed, the Bingham Plastic. Bingham Plastic assumes a straight linerelationship with the slope of the line names Plastic Viscosity, PV, and the intercept with the Yaxis, YP, the Yield Point.

Bingham Plastic model

SHEAR RATE γ

SHEARSTRESS

τ

µ

SHEAR RATE γ

SHEARSTRESS

τ

600300

PV

YP


LOGGING SYSTEMS

Fortunately, improvements in rheological test equipment revealed that the relationship was nota straight line, but a curve.

By plotting the data on log-log paper the linear relationship is restored and the PV and YPvalues replaced by n and k. This is the basis of the Power Law model

n and k are directly related to the mud viscosity characteristics by the following formulae

n = 3.32 log θ600 / θ300 k = θ300 / 511n

Having established the rheological basics, they can be used to model the flow and pressureenvironment in the circulating system.

Flow regimes

In the circulating system three distinct flow regimes can be identified: laminar, transitional andturbulent.

Laminar - as the name suggests involves concentric layers (shear planes) of mud flowingthrough the pipe work, with little intermixing of the layers. Velocity increases toward the centreof the flow, with the boundary layer being stationary.

Transitional - as its name suggests, this is the transition zone between laminar and turbulent. NB - Planit and the LS2000 hydraulics applications do not identify transitional flow.

Turbulent - at high flow rates the shear planes have broken down and the mud tumblesthrough the pipe work, with velocity constant across the flow area, apart from the thinboundary layer.

Laminar flow is desirable in the annulus as turbulent flow causes borehole erosion. Turbulentflow may be desirable in high angle holes, to break up cuttings beds.

The regimes are defined by Reynolds numbers. When calculated for a particular hole section,if the Reynolds number is greater than 2000, then the flow regime is probably turbulent.

LOG SHEAR RATE γ

LOGSHEAR

STRESSτ

600300

n

k


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Pressure losses and hydraulic horsepower

Power law enables the pressure losses in the different sections of the system including the allimportant bit pressure loss, to be calculated. As mentioned above it is desirable for themaximum amount of energy in the system to be expended at the bit. This energy is used toclean the bit and provide jetting of the formation. This is usually expressed as a percentage ofthe total system energy, or total system pressure loss.

Optimising for HHP - When calculating pressure losses to optimise drilling performance it isusual to talk about Hydraulic Horsepower HHP. Hydraulics are said to be optimised when 65%of the available HHP is used up at the bit. In practice this percentage cannot always bemaintained due to the presence in the string of tool such as MWD and motors. Optimising forHHP, by using smaller jets and lower flow rates, reduces annular velocities, annular pressuredrops and ECD. These help to prevent possible hole damage.

Optimising for Impact - when 49% of the available energy is expended at the bit, by way ofincreasing the jet size and flow rate. This is desirable in situations where hole cleaning is mostimportant, such as top hole.

Annular pressure losses and ECD

Effective Circulating Density - dependent on the mud properties, flow rate and annularconfiguration. ECD is the pressure generated by the friction losses in the annulus acting onthe mud column, thereby increasing the effective density of the mud.

Hole cleaning

Drilling generates cuttings which must be removed from the hole. This is dependent on thelifting capacity of the mud and the annular velocities of the various sections. The liftingcapacity of the mud varies depending on the flow rate as most muds are thixotropic, the fasterthey are sheared the thinner they become, thus reducing their lifting capacity.

Cuttings slip velocity - a particle in a fluid will fall under the force of gravity, but its slipvelocity is governed by its density and the rheology of the fluid. As mentioned above high flowrates thin mud, reducing the lifting capacity, so a particle in a high flow rate annulus will have ahigher slip velocity than a particle in a lower flow rate annulus. The actual cuttings velocity inthe annulus is the fluid velocity minus the slip velocity. Attention should be paid to the largestannulus section, particularly marine risers, as the slip velocity may exceed the annularvelocity. If this is the case it may be necessary to use a riser boost pump.

Swab / Surge

Moving pipe in the hole causes the drilling fluid to move, generating pressure. Hydraulicsanalysis allows these pressures to be calculated and their effects controlled. These pressuresare referred to a swab (a reduction in pressure) and surge (an increase in pressure)

Mechanism - Whenever pipe is moved in the hole both swab and surge effects occur, due tothe flow of mud around the pipe. Pressure is generated in the opposite direction to pipemovement, mainly due to mud being displaced by the pipe or moving into the space formerlyoccupied by the pipe. Speed of pipe movement has a great effect on swab/surge pressures,with the maximum pressure generated at maximum pipe speed. If the pipe is closed ended


LOGGING SYSTEMS

(e.g. blocked jets or a float valve) the pressures are greater still due to lack of equalisationbetween fluid around the string and fluid in the string.

Pressure effects of lowering a joint of pipe into the hole

Breaking gels can also add to the surge effect of moving pipe. It is good practice to breakcirculation when running in the hole to break the gels to prevent problems when tripping in thehole.

Problems associated with swab / surge

As described above, when the pipe is moved when tripping or running casing, pressures aregenerated in the mud column. These act to increase or decrease the static mud weight, evenif momentarily. These can affect the bore hole in a variety of ways:

Swab - if the negative pressure is great enough, the mud hydrostatic can drop below that ofthe pore pressure. If there is porosity and permeability in the formation, pore fluid can beswabbed into the annulus.

Pressure

+ve

- ve

TimeA

B

C

D

E

A - pipe lifted out of slipsproducing swab pressure

B - surge pressure to breakmud gel

C - minimum run speed

D - Maximum run speed

E - swab as pipe stopsabruptly


LOGGING SYSTEMS

In the snapshot above, the string has become stuck and in the course of freeing the pipe fluidhas been swabbed into the annulus. This shows as a gain in the trip tank.

Surge - if positive pressure is great enough to exceed the fracture pressure of the formation,fractures may be initiated and propagated, causing losses or formation damage.

Before every trip out or in the ADT engineer should produce a report of the expected swab /surge pressures with maximum running speeds. Especially prior to casing runs, where goodswab / surge information can prevent potentially serious hole problems. Liase with Operatorpersonnel to define the pressure limitations and constraints.


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In the case above, It was thought that the formation was broken down by surging (mud weight820 pptf, minimum open hole fracture gradient calculated to be 843pptf, Leak Off at 13 3/8”shoe was 863 pptf. Operator insisted that the LOT was the lowest fracture gradient. Thecasing surged, fractured the formation and 110% losses occurred. Very expensive.

Conclusion

Hydraulics optimisation is one of the main tasks of the ADT engineer. Modern applicationsmake the calculations easy, but some interpretation and experience is required. Running bitswith poor bit hydraulics is a costly business.

The ADT engineer must be aware of the limiting factors when optimising hydraulics. Factorssuch as pore pressure and fracture gradient are the obvious ones, but the pump pop-offsettings must always be considered, as should the pressure drops due to mud motors andMWD tools.

Hole cleaning is important, but care must be taken to prevent borehole erosion. Occasionallythe guidelines are broken, e.g. in high angle holes where cuttings beds must be broken up.

Both swab and surge effects are present whenever pipe is moved in the hole and againvarious constraints may limit the scope for run speeds. Recent developments with PWD(pressure while drilling) allow downhole pressures to be measured, leading to a new field ofhydraulics analysis.


LOGGING SYSTEMS

Well Control

This is a very brief introduction to well control. If a well control situation is encountered, ensurethat the senior engineer is aware of it and takes charge in the unit. The work load on the unitin this situation can be high and as much information as possible should be recorded.

A kick is a situation where the formation pressure has exceeded the hydrostatic pressureexerted by the mud i.e. there is a hydrostatic underbalance. In a formation where there is littleor no porosity or permeability, this manifests itself by swelling shale, caving and high gaslevels. In a porous and permeable formation, the pore fluid can enter the annulus. This fluid iscalled an influx. Influxes can be gas, oil, fresh water, salt water or a mixture.

Causes - Kicks are usually the result of a series of events which lead to negative differential(underbalance) between the hydrostatic head of the mud and the formation pressure. Mostkicks are caused by the following:

1) Swabbing during a trip

2) Failing to keep the hole full while tripping

3) Lost circulation

4) Drilling into a high pressure zone

5) Shallow gas

Shutting in - On detecting a possible kick, e.g. if a flow check showed that the well wasflowing, the driller would space out the pipe to ensure that no tool joints will foul the BOP rams,then shut the well in.

Depending on the situation the well may be shut in hard or soft. On a hard shut in, the annularpreventer is closed with the choke shut. Hard shut in can cause formation breakdown due to“water hammer”, but is quicker than the soft shut in. On a soft shut in, the choke valve isopened prior to the annular preventer being closed. The disadvantage of the soft shut in is thatit allows additional influx to enter the annulus.

BOPs can have 4 types of closure devices - Annular preventer (Hydril or “the bag”) which is arubber doughnut shape which is compressed to fit around any object in the BOP. Pipe ramswhich are shaped to fit around drillpipe or collars. Shear rams cut the pipe while blind ramsclose against each other to seal the hole. Most BOPs are operated pneumatically by theKoomey unit.

Stripping in - if a kick is taken while off bottom, it is advisable to attempt to run back in tobottom. Obviously running in conventionally will allow more influx into the annulus, so the pipeis “stripped” through the annular preventer, with the displaced mud bled off as the pipe is runin.

Taking the pressures - having shut the well in, the next step is to take the various pressures.These pressures will govern how the well is killed. Having allowed the pressures to stabilise,the Shut In Casing Pressure and Shut In Drill Pipe Pressure are required. Normally the influxwill enter the annulus, so reducing the hydrostatic head of the mud. Therefore the SICP will behigher than SIDPP.


LOGGING SYSTEMS

Calculating the kill mud weight - by using the formula

Kill mud weight = (SIDPP/(0.O52 x TVDft))+ MW

The density of the mud to balance the formation pressure can be established. Usually a safetyfactor is added to this mud weight to produce an overbalanced situation. Overkilling the wellwith excessive mud weight can damage the well.

Influx density - the manner in which the well will be killed will be governed by the nature ofthe influx. Gas kicks can produce some dramatic effects during a kill operation, so priorknowledge of how the well should react does help. The height of influx is required to calculatedensity, as is the SICP and SIDPP.

Height of influx = PIT GAIN(bbls) / ANNULAR VOLUME(bbls/ft)

Next the influx density can be calculated. Kicks are always assumed to be gas until provenotherwise.

SICP - SIDPP

Gradient of influx (psi/ft) = MUD GRADIENT - ----------------------

INFLUX HEIGHT

INFLUX GRADIENTS

GAS 1 - 3 ppg

GAS/OIL/WATER 3 - 5 ppg

OIL/WATER 5 - 7 ppg

SALT WATER 8 - 12 ppg

The aims of well control : maintain constant bottom hole pressure, thus preventing furtherinflux, remove the influx from the well bore and return the well to equilibrium. By introducing anew mud to the well, the hydrostatic overbalance can be regained.

To kill the well by whatever method, the initial and final circulation pressures must becalculated. It is normal drilling practice to record Slow Circulation Rates (SCRs) once a tour, orwhen mud properties change. The pumps are run in turn at the rate to be used to kill the welland the pressures recorded. These are the circulating system pressure losses.

Before killing the kick, the initial circulating pressure is calculated:


LOGGING SYSTEMS

Initial Circulating Pressure = SIDPP + KRP*

*From SCRs

The final circulating pressure is then calculated:

Final Circulating Pressure = KRP x (KILL MW / MW)

These pressures allow a Drill Pipe Pressure schedule to be drawn up. This has pumppressure on the Y axis and Stroke pumped on the X axis. As the drillpipe pressure will fall at aconstant rate during the kill, the graph can be drawn using the ICP and FCP alone.

While the kill operation is underway, the choke valve should be opened or closed to ensurethat the drill pipe pressure follows the line on the graph.

Procedures for killing a wellThere are 3 methods of killing a well, differences between methods are generally determinedby the number of circulations required and pressures generated.

a) Wait And Weight Method : the well is shut in, kill mud is weighted up, then pumped. Killis achieved in one circulation. When the kill mud has reached the bit, the well is dead. Alsoknown as the Engineer's method. Circulation continues until the influx is out of the annulus.W+W Produces the lowest casing shoe and annular pressures, but requires longer non-circulating time.

b) Driller's Method : the well is shut in, the influx is circulated out. Kill mud is then pumpedwith the well being dead when the kill mud reaches the bit. The well is killed in two circulationswith higher casing shoe and annular pressures than the Engineer's method

c) Concurrent Method : the well is shut in, circulation begins as the mud is weighted up inincrements. May require a number of circulations to kill the well. Requires more on-chokecirculating time and produces higher casing shoe and annular pressures than engineer'smethod. May be used in the event of rapid gas migration.


LOGGING SYSTEMS

MAASP - the pressure effects on the well bore are due to gas expansion as the influx iscirculated out. If the pressure exerted by the gas and mud column exceeds the fracturepressure of the formation, a sub surface blow out may occur. When the formation fractures,the influx may escape into the formation, leading to a loss of hydrostatic head. This in turnleads to more influx entering the annulus. To ensure that this does not occur the MaximumAllowable Annular Surface Pressure (MAASP) is calculated.

MAASP = 0.052 x TVDft CASING x (LOT - MW)

Gas migration - If a gas kick has occurred and the pumps are off, a gas influx will start tomigrate upwards. As it migrates, the mud hydrostatic will be reduces. As the hydrostatic falls,the gas will expand. This can be dramatic, especially near the surface, and may displace mudfrom the annulus, (annulus unload) allowing more influx into the annulus. If the well has beenshut in, migration still takes place, but expansion will not occur as the system is closed.


LOGGING SYSTEMS

PWD and ECD - a quick guide

This guide assumes absolutely no knowledge of drilling hydraulics, so be prepared to bepatronised. Apologies in advance.

PWD allows the Equivalent Circulating Density of the drilling fluid to be observed in real timeand recorded for end of run analysis.

What is ECD? - The Equivalent (or effective) Circulating Density is the actual pressureexerted on the borehole by the drilling fluid while the fluid is being circulated. When a drillingfluid is static in the borehole it exerts a pressure which is dependent on:

a) density of the fluid

b) depth (always True Vertical Depth)

To calculate this pressure, a constant is used. This constant varies depending on the units ofmeasurement in use:

Pounds per Gallon (ppg) and feet (ft) the constant is 0.0519

Specific Gravity (sg) and Metres (m) the constant is 1.421

To calculate a pressure in psi,

ppg x 0.0519 x ft or if metric units are in use, sg x 1.421 x m

This gives a static pressure.

Pressure losses - Friction in a circulating system is seen as a pressure on a gauge. Themagnitude of this pressure depends on the point at which the measurement is taken.

In the case above, the pressure gauge at A will show the frictional pressure loss for the entirecirculating system from A to C. The pressure gauge at C will show zero psi as there is nofrictional loss upstream from C, as this is the outfall to the flow line. The gauge at B will onlyshow the frictional loss from B to C.

Consider this diagram as being representative of the well with A to B representing the drillstring and bit, B to C representing the annulus. The gauge at B represents the PWD sensorand therefore can only measure frictional loss in the annulus plus the static pressure of thedrilling fluid. This pressure is the annular circulating pressure.

Equivalent Mud Weight - Having measured this effective circulating pressure, it can beconverted to an Equivalent Mud Weight (EMW) by using the same constants as above:

A B C

PUMP FLOW LINE


LOGGING SYSTEMS

ppg = psi / TVD ft / 0.0519 or if metric units are in use, sg = psi / TVD m / 1.421

The system uses a pair of high accuracy quartz gauges, one open to the annulus, the otheropen to the bore of the collar. The annular gauge measures the frictional pressure loss in theannulus. Being a sum of the static mud pressure and the annular frictional pressure loss, thisrepresents the actual pressure being exerted on the borehole. The PWD software convertsthat pressure to an Equivalent Mud Weight, but only if the relevant survey information isavailable to calculate True Vertical Depth, which is then used in the calculation of EMW. Whenconverted to an EMW, this is the Equivalent Circulating Density (ECD).

Why use Equivalent Circulating Density? ECD allows comparison of the actual pressureexerted on the formation while circulating and the static pressure exerted by the mud. ECD willbe greater than the static mud weight by a factor which depends on the drill string and holegeometry, mud properties, amount of cuttings suspended in the mud and flow rate. The PWDtool allows direct measurement of ECD and actual static mud weight, which will vary from thatreported by the mud engineer as soon as any cuttings enter the mud column. Before PWDtools became available the ECD had to be modeled from hydraulics models.

Now that a real time measurement of ECD is available, it is possible to assess its impact onthe down hole environment.

The mud weight should be sufficient to control formation pressures without exceeding thefracture pressure of the formation.

Fracture Pressure - Is the pressure required to initiate fractures within the formation matrix.These fractures may propagate if the applied pressure exceeds the initiation pressure.fractures lead to lost circulation, subsurface blow outs and ultimately to severe drillingproblems. The fracture pressure is calculated by ADT engineers as the well is drilled using theDaines Fracture pressure model. This gives a calculated value for fracture pressure, but anactual value of fracture pressure can be obtained from Leak Off Tests (LOT). These areusually done after drilling out from a new casing string. Casing is normally set in a highstrength formation such as a claystone, providing a maximum fracture pressure at that depth,but if a low strength formation such as a sand is encountered the fracture pressure maydecrease. Some operators consider the leak off value to be the lowest fracture gradient in theopen hole section, but this may not always be the case.

More wells are being drilled under High Pressure / High temperature (HP/HT), these beingcharacterised by having high formation pressures close to the formation fracture pressure.This means that to balance the formation pressure without fracturing the formation, the mudweight must not fall below the formation pressure or exceed the fracture pressure. The mudweight and the ECD must be in a “window” defined by pore pressure and fracture pressure.PWD allows the ECD to remain within this window by providing the information to allowmodification of drilling pactices.

If the EMW falls below the formation pressure, the hole may become unstable and collapse orif circumstances permit, the well may kick. If the EMW exceeds the fracture pressure, theformation may break down, causing losses, which may ultimately lead to a kick.


LOGGING SYSTEMS

In the above diagram, the relationship between Pore pressure, fracture pressure, static mudpressure and ECD can be seen. At point A the “window” between the ECD and fracturepressure is large enough and poses no problem. At B the window has reduced to the extentthat if the ECD rises, the fracture pressure may be exceeded and problems occur. At C theECD is the same as the fracture pressure and may have already fractured the formation. Notehow fracture pressure changes with lithology type.

Swab and SurgeThe equivalent mud weight is also affected by movement of the drill string whether the pumpsare on or off. The simplest analogy is to consider the bit as a piston and the borehole as thecylinder. As the string is moved up and down, pressures are generated at the bit. Moving thebit up will reduce the pressure under the bit, reducing the EMW of the mud. This is calledswabbing. Moving the bit down creates positive pressures, called surging.

Swab / Surge mechanism and effects

Moving pipe in the hole causes the drilling fluid to move, generating pressure. Hydraulicsanalysis allows these pressures to be calculated and their effects controlled. These pressuresare referred to as swab (a reduction in pressure) and surge (an increase in pressure). Thesepressure changes can be seen on the PWD tool (recorded only at present) and allow directcomparisons to be made with calculated values.

DEPTH

ECD

Pore pressureMud weight

Fracture

A

B

C

EMW


LOGGING SYSTEMS

Mechanism - Whenever pipe is moved in the hole both swab and surge effects occur, due tothe flow of mud around the pipe. Pressure is generated in the opposite direction to pipemovement, mainly due to mud being displaced by the pipe or moving into the space formerlyoccupied by the pipe. Speed of pipe movement has a great effect on swab/surge pressures,with the maximum pressure generated at maximum pipe speed. If the pipe is closed ended(e.g. blocked jets or a float valve) the pressures are greater still due to lack of equalisationbetween fluid around the string and fluid in the string.

Pressure effects of lowering a joint of pipe into the hole

Breaking gels can also add to the surge effect of moving pipe. It is good practice to breakcirculation when running in the hole to break the gels to prevent problems when tripping in thehole.

Problems associated with swab / surge

As described above, when the pipe is moved when tripping or running casing, pressures aregenerated in the mud column. These act to increase or decrease the static mud weight, evenif momentarily. These can affect the borehole in a variety of ways:

Swab - if the negative pressure is great enough, the mud hydrostatic can drop below that ofthe pore pressure. If there is porosity and permeability in the formation, pore fluid can beswabbed into the annulus. A kick.

Surge - a positive pressure can induce and propogate fractures with the same consequencesas increased ECD. Formation fracture, lost circulation.

Hole cleaningAs mentioned above the amount of cuttings in the annulus can effect the static EMW and theECD. From this the annular pressure can be used to determine the amount of cuttings in theannulus and therefore how well these cuttings are being removed from the well bore. Holecleaning is a function of cuttings size and density, mud rheology and flow rate. Flow rate isprobably the most important factor, but in high angle holes string rotation becomes important.In a vertical hole an increase in the PWD EMW would indicate that the cuttings load is buildingup (usually in the largest annular section eg the riser) and this can be cleared by increasingthe flow rate. If cuttings do build up in an annular section, there is a possibility that a pack-offwill occur, exerting excess pressure on the wellbore and causing formation fracture.

Pressure

+ve

- ve

TimeA

B

C

D

E

A - pipe lifted out of slipsproducing swab pressure

B - surge pressure to breakmud gel

C - minimum run speed


LOGGING SYSTEMS

In a high inclination hole (50° +) cuttings beds (or dunes) can form on the low side of the hole,especially when the drillstring is not being rotated during long periods of sliding. This shows onthe PWD EMW as a gradual decrease. When rotation resumes a sharp increase in PWDEMW will be observed as the cuttings beds are stirred up into the mud column.

As with most drilling parameters trends and changes rather than absolute values are morerelevant to PWD monitoring.

The above log shows how annular pressure increases due to variations in the cuttings load inthe annulus. In this case ROP had increased (due to increasing formation pressure) over theprevious 30 minutes. The hole was being under-reamed and as the cuttings entered thesmaller ID of the casing the ECD increased, exceeding the formation fracture gradient. Lostcirculation followed and remedial action had to be taken.

Conclusion

PWD allows realtime measurement and monitoring of the ECD. This allows the ECD to bemanaged with the aim of minimising hole problems.

Date post:	23-Oct-2015
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