UNDERBALANCED OPERATIONS

DISSERTATION SUBMITTED

IN PARTIAL FULFILMENT OF THE REQUIREMENT

FOR THE AWARD OF THE DEGREE OF

MASTER OF TECHNOLOGY

IN

PETROLEUM ENGINEERING

By

PRAVEEN PATHAK Roll No. 08MT1004

SCHOOL OF PETROLEUM TECHNOLOGY

PANDIT DEENDAYAL PETROLEUM UNIVERSITY

GANDHINAGAR, GUJARAT, INDIA 18

th JANUARY 2010

UNDERBALANCED OPERATIONS

DISSERTATION SUBMITTED

IN PARTIAL FULFILMENT OF THE REQUIREMENT

FOR THE AWARD OF THE DEGREE OF

MASTER OF TECHNOLOGY

IN

PETROLEUM ENGINEERING

By

Praveen Pathak Roll No. 08MT1004

Under the supervision

of

Prof. S.S.P. Singh

SCHOOL OF PETROLEUM TECHNOLOGY

PANDIT DEENDAYAL PETROLEUM UNIVERSITY

GANDHINAGAR, GUJARAT, INDIA 18

th JANUARY 2010

ii

18/01/2010

CERTIFICATE

This is to certify that the dissertation entitled “ Underbalanced Operations” submitted by

Praveen Pathak (Roll No: 08MT1004) in partial fulfillment of the requirements for the award of

the degree of Master of Technology in Petroleum Engineering, from School of Petroleum

Technology, Pandit Deendayal Petroleum University, Gandhinagar was carried out under my

guidance and supervision. No part of this dissertation has been submitted for the award of any

degree or otherwise elsewhere to the best of my knowledge.

(Prof. S.S.P.Singh)

School of Petroleum Technology, Gandhinagar

Forwarded by:

(Dr. Shrikant J. Wagh)

School of Petroleum Technology, Gandhinagar

iii

ACKNOWLEDGEMENTS

I would like to take this opportunity to express my deep sense of gratitude and profound feeling

of admiration for Prof. SSP Singh, Ex.GM (Prod.) and Head Well Stimulation Services ONGC

Ltd. His student friendly attitude, involvement and guidance has provided me good atmosphere

to develop my research capabilities. Also his regular assessment and feedback helped me to

complete my project within timeframe.

My heartiest thanks to Mr. V.K Jain (ED-Ex. Head IDT) and Mr. S.K. Dutta (GGM- Head IDT)

for providing me an opportunity to work at the Institute of Drilling Technology, ONGC,

Dehradun.

Very sincere and honest thanks to Dr. Vinod Sharma (GM- Chemistry), for granting permission

to work and utilize the laboratory facilities at R&D Lab Chemistry division at IDT Dehradun. I

also like to acknowledge Mr.A.K.Barthwal (CC), Dr. V.K.Singh (CC) and all other personal at

IDT for their kind support and continuous motivation during my experimental work.

I would like to express my appreciation to all members of PG committee, School of Petroleum

Technology, Gandhinagar for their regular evaluation and guidance. I would also like to convey

my thanks to the whole PDPU members who helped me directly and indirectly during my project

work.

I am heartily grateful to my family members for their blessings and motivation.

iv

(Praveen Pathak)

ABSTRACT

Formation damage to some extent occurs in all wells. As a result the objective of drilling, completion and workover designers is to reduce the effects of damage to economically acceptable levels. The underbalanced operation is one such technology to exploit the formation to its full potential.

At present many of the onshore reservoirs of India are in depleted conditions with good amount of recoverable reserves. Various issues involved in the underbalanced operations have been investigated. Laboratory screening procedures for evaluating the effectiveness of underbalanced operation for a specific application has been elaborated. Benefits and limitations of underbalanced operations are identified. Appropriate candidate selection for underbalanced operations is elaborated. Fluid operations used in underbalanced techniques are also discussed.

The project provides a detailed study in how to plan for underbalanced operations to achieve success in drilling, completion and workover to the oil field. The study emphasizes advantages of this technology, formation stability, well control, environmental restrictions, minimize / avoid formation damage with employing non-damaging fluid and the development of water based low gravity workover fluid formulations for sub-hydrostatic reservoir field. It is very difficult to maintain the underbalanced condition during horizontal well operations due to poor hole cleaning. In that case formation damage occurs when underbalanced condition is lost, for such condition laboratory experiments and evaluation of non-damaging fluid at bottom hole environment is performed which will provide guaranteed economic incentives.

The technology implementation would minimize formation damage, reduce requirement of subsequent stimulation/activation jobs, and would result in higher productivity gain.

Objective of the project is to improve the productivity from sub-hydrostatic Indian reservoirs.

v

CONTENTS

Title ……………………………………………………………………………………………….i

Certificate ………………………………………………………………………………………..ii

Acknowledgements ……………………………………………………………………………..iii

Abstract .........................................................................................................................................iv

List of Tables …………………………………………………………………………………..viii

List of Figures …………………………………………………………………………………...ix

Abbreviations …………………………………………………………………………………...xi

Nomenclature …………………………………………………………………………………..xii

CHAPTER 1 Introduction of Underbalanced Operations 1

1.1What is Underbalanced Operations? 1

1.2 History of Underbalanced Operations 3

CHAPTER 2 Literature Survey 5

2.1 Underbalanced Operations 5

2.1.1 Underbalanced drilling 5

2.1.2 Underbalanced perforation 14

2.1.3 Underbalanced workover 17

2.2 Underbalanced Fluid System and Techniques 20

2.2.1 Selection of an underbalance operations fluid 20

vi

2.2.2 Underbalanced operational fluid design aspects 20

2.2.3 Fluid system selection 22

2.2.3.1 Gasified (Aerated) fluid operations 22

2.2.3.2 Foam fluid operations 30

2.2.3.3 Mist fluid operations 37

2.2.3.4 Air and gas fluid operations 39

2.3 Candidate Screening and Selection 43

2.3.1 Drivers to consideration of underbalanced operations 43

2.3.2 Reservoir aspects of underbalanced operations 44

2.3.2.1 Good candidate indicators for underbalanced operations 44

2.3.2.2 Bad candidate indicators for underbalanced operations 45

2.3.3 Assessing rock potential for formation damage 46

2.3.4 Assessing lost circulation potential 53

2.3.5 Assessing pipe sticking possibility 54

2.4 Well Control Aspects in Underbalanced Operations 55

2.4.1 Blow out prevention system 55

2.4.2 Sub-surface control system 55

2.4.3 Well control equipments 56

2.5 Problem Identified 58

vii

CHAPTER 3 Methodology & Experimental work 59

3.1 Development and Evaluation of Low gravity, Non invasive Fluids for

Sub- hydrostatic Underbalanced Workover Operation 59

CHAPTER 4 Results and Interpretations 76

CHAPTER 5 Conclusion and Recommendations 80

5.1 Conclusion 80

5.2 Recommendations 80

5.2.1 Recommendations for underbalanced drilling 80

5.2.2 Recommendations for underbalanced workover 82

5.2.3 Recommendations for underbalanced perforation 82

APPENDIX

REFERENCES

viii

LIST OF TABLES

2.1 IADC fluid classification…………………………………………………………………….22

2.2 IADC UBO Committee classification system for UBD wells……………………………….46

2.3 Main components of various clay and fine particles………………………………………...47

2.4 Damage indices for pure clays……………………………………………………………….49

2.5 Distribution correction factors……………………………………………………………….49

2.6 Damage mechanism vs. formation type matrix……………………………………………...52

ix

LIST OF FIGURES

2.1 Conventional Overbalanced Vs Underbalanced Operations……………………………….5

2.2 Pseudo-steady-state depletion condition near well bore region during underbalanced

drilling condition…………………………………………………………………………..9

2.3 Invasion during an overbalanced/reduced underbalanced condition phase in the near

wellbore depletion region………………………………………………………………….9

2.4 Gravity induced invasion in horizontal well UBO………………………………………..10

2.5 Fluid loss and solid loss in overbalanced /underbalanced operations……………………..11

2.6 Snubbing system…………………………………………………………………………..18

2.7 Various flow regimes in horizontal wells during gasified (aerated) fluid operation……...23

2.8 Compression of the fluid at different depths in a wellbore decreases hydrostatic pressure

disproportionately…………………………………………………………………………24

2.9 Gasified mud injection reduces BHP……………………………………………………..25

2.10 Formation damage reduction in gasified systems………………………………………...25

2.11 Differential sticking results from higher pressure exerted by mud than the formation

fluids……………………………………………………………………………………...26

2.12 ROP decreases as BHP increases…………………………………………………………27

2.13 Inconsistent pressure in UBO…………………………………………………………….27

2.14 BHP remains much more constant with gas circulation before connections……………..28

2.15 Parasite tubing string……………………………………………………………………...29

x

2.16 Concentric casing string…………………………………………………………………..30

2.17 Foam is made of bubbles that are surrounded by a liquid film…………………………...31

2.18 Large cutting cleaning in foam drilling operations……………………………………….32

2.19 Difference in phases between foam and a mist system…………………………………...33

2.20 Foams reduces BHP, avoiding lost circulation…………………………………………...34

2.21 Foams minimize reservoir damage because flow is from the reservoir to the wellbore….34

2.22 In UB Operations with foam, reservoir pressure is higher than wellbore pressure,

differential sticking can not occur………………………………………………………...35

2.23 Mist formed by water drops in suspension………………………………………………..36

2.24 Shales destabilized by water invasion cause formation of mud rings, which clog

the hole…………………………………………………………………………………….40

2.25 Mud ring formation and downhole fire……………………………………………………41

2.26 Oxygen partial pressure in distilled water………………………………………………...42

2.27 Angel’s Curves for air drilling…………………………………………………………….43

2.28 Relative permeability curves ……………………………………………………………..50

2.29 Jointed pipe system for well control………………………………………………………56

2.30 Coiled tubing system for well control……………………………………………………..57

4.1 Hollow glass spheres Vs specific gravity, Fluid formulation table A1…………………...78

4.2 Hollow glass spheres Vs specific gravity; Fluid formulation table A2…………………...78

4.2 Hollow glass spheres Vs specific gravity; Fluid formulation table A3…………………...79

4.3 Hollow glass spheres Vs specific gravity; Fluid formulation table A4…………………...79

xi

ABBREVIATIONS

UBO Underbalanced operations

UBD Underbalanced drilling

ROP Rate of penetration

BHP Bottom hole pressure

FD Formation damage

IADC International association of drilling contractors

mD Mille darcy

PI Productivity index

PBR Polished bore receptacle

TCP Tubing conveyed perforation

BOP Blow out preventer

Pu Minimum required underbalanced

SEM Scanning electron microscope

PPM Parts per million

NPT Non productive time

BHA Bottom hole assembly

SOL The percentage of solids in drilling fluid

EMW Effective mud weight in the annulus

DIA Hole diameter

ERCB Energy resources conservation board

RBOP Rotating blowout preventer

ESD Emergency shutdown

HGS Hollow glass spheres

TVDSS Total vertical depth subsea

AHD Australian height datum

xii

NOMENCLEATURE

K Permeability (mD)

Kh Formation flow capacity (m3)

h Thickness of reservoir (m)

µ Viscosity of reservoir fluid (cP)

Bo Oil formation volume factor (rb/stb of oil)

re Radius of drainage (m)

rw Radius of well (m)

L Length (m)

S Skin factor (dimensionless)

Q Flow rate (m3/s)

∆Ps Pressure drawdown (psi)

IFr Fracture index

ILC Lost circulation index

IV Vugs index

CC Cuttings concentration (%)

AV Apparent viscosity (cP)

PV Plastic viscosity (cP)

YP Yield point (lb/100ft2)

Gel0 Initial gel strength (lb/100ft2)

Gel10 Gel strength after ten minutes (lb/100ft2)

1

Chapter 1: Introduction of Underbalanced Operations

1.1 What is Underbalanced Operations?

Underbalanced operations (UB operations) have been defined as a condition generated any time

the effective circulating downhole pressure of a drilling, completion, stimulation or workover

fluid (the pressure exerted by the hydrostatic weight of the fluid column and the associated

frictional pressure drop) is less than the effective pore pressure in the formation adjacent to the

sand face [Medley G.H.et al., 1998]. It implies the use of particular equipment and techniques to

handle formation fluids entering the well and going up to the surface [Rehm B., 2002].

Underbalanced operations are used increasingly in oil field operations as well as in extraction of

coal bed methane as an alternative technique to conventional overbalanced operations to reduce

invasion near wellbore formation damage problems in producing formations. If underbalanced

operations are properly designed and executed, it can eliminate or significantly reduce formation

damage due to mud or drilled solids invasion, lost circulation, fluid entrainment and potential

adverse reaction of invaded drilling or completion fluids with the reservoir matrix or in-situ

reservoir fluids.

Underbalanced operations are not a panacea, but when properly applied, the time, productivity

and economic results can be significant. Application of a poorly planned and designed

underbalanced operations can often results in additional cost, greater formation damage, and

reduced production compared with a well-designed conventional overbalanced program.

Several studies have been focused in underbalanced operations which provide its definition,

advantages, disadvantages, case studies, fluid hydraulics and equipments used in the operations.

It is stated that underbalanced operations is a very complex process which should not be

designed and implemented on a gut feel basis, or because it appears to be the trendy approach to

a difficult problem. Underbalanced operations provide a new technological approach to resolve

2

complex reservoir management problems and results the economic completion as well as

exploitation of reserves unobtainable by any other type of currently available technology [Qutob

H. et al., 2005]. The implementation of this technology for Indian Sub-hydrostatic reservoirs will

be beneficial.

The success of UB operations is described in many case studies which results in less completion

time of the operations compared to overbalanced techniques. [R.A. Joseph, 1995]The author

describes the planning, procedures and well design to alleviate formation damage from the mud

and tool failures from high temperature in the Austin Chalk play which is one of the first fields

where underbalanced technology started gaining more acceptances in the U.S. after the great

success achieved in this field. Then, the author addressed the complications during the operation

and the equipment used. The operating parameters and results experienced for dual-lateral

horizontal wells in depleted reservoirs of Libya obtained during the UBO is discussed by the

author [Hussein S. et al., 2007]. Another study [C.P. Labat et al., 2000] shows how

underbalanced operations along the Gulf of Mexico coast brought new life to an old oil field, it

reviews how detailed safety hazard analysis and proper planning resulted in a safe and successful

operation even under the most extreme design and regulatory requirements.

[D.M. Hannegan, 2001] Hannegan provides a discussion of underbalanced operations future in

offshore applications, the author mentions that UBO is expected to revolutionalize deepwater

drilling because it is estimated that approximately 20-30% of the known world’s offshore oil and

gas resources cannot be economically developed with current drilling methods, due to the

depletion aspect as well as the deepwater limitations. The author describes about the key

situations that are typically encountered during drilling offshore and make comparisons between

conventional methods and underbalanced technology. The latest technology was reviewed to

illustrate how underbalanced drilling at offshore can be safe and sufficient to achieve a

“successful” well from multiple perspectives.

[Vieira P. et al., 2007] This study presents an expert system that can screen rock parameters

required to design an effective underbalanced operation. Once it is concluded that a particular

reservoir presents a good candidate for underbalanced technology, the system goes through

3

another screening procedure to select optimal UBO fluid. These screening procedures assess

formation damage potential, lost circulation possibilities, and assure wellbore stability. After

determining the optimal UBO fluid, the system will determine the optimal circulation rate that

assures an effective underbalanced operation.

1.2 History of Underbalanced Operations

A number of wells drilled initially in eighteenth century were drilled underbalanced. These wells

were operated with fluid column pressure in the annulus compared to the adjacent formation, but

these wells were collapsed when well flows through a permeable zones. Being an uncontrolled

flow this resulted in lost reserves. The earliest underbalanced operation patent can be traced back

to the mid-1800s.The patent was issued for using compressed air to clean out cuttings from the

bottom of a hole. Advances in the UBO continued in the exploration of hydrocarbon throughout

the mid-1900s. Then after use of mist and multiphase fluids to control downhole fires in air/gas

fluid operations started and provide a higher tolerance to water influxes. Algorithms and

equations were developed to predict the amount of gas required to clean holes and the bottom-

hole pressure resulting from circulating mixtures of fluid and gas. Advances were made in

understanding and modeling of air and multiphase systems. This technology enhancement

continued into the early nineteenth century with the first application of multiphase fluids

occurring in the 1930s.

The use of multiphase fluids, air and natural gases mixed with water or oil, became used in oil

well operations in the 1930s. Mist fluid system in underbalanced operations was first introduced

in late 1930s. Drilling underbalanced with pure air or natural gas also increased at this time.

Closed systems were started in use to capture produced fluids and improve safety. Foam came

into underbalanced operation fluid system in the 1960s because of its characteristics of better

hole-cleaning capability as compared with air and multiphase systems. UB technology was used

in limited applications before 1970s. Limitations were due to environmental problems,

particularly in gas fluid systems, where large amounts of dust were released into the atmosphere.

In single-circulation foam systems, the waste generated was a serious concern. Most wells drilled

4

underbalanced prior to 1985 were low-pressure applications. The primary aim of many of these

applications was to increase the rate of penetration (ROP) in non-productive zones.

New technologies developed in the late 1980s and through the 1990s have seen a reemergence

of UBO, with improvements in multiphase modeling capabilities and the development of higher

pressure rotating control heads. Rotating heads have been available for decades in drilling

operation industry but innovation since 1987 has brought about the development of rotating

control devices capable of withstanding up to 3,000 psi while drilling. Thus this pressure rating

of RCD has greatly expanded the applicability of underbalanced operations.

Underbalanced operations have since proven to be an effective technology in minimizing the

damage during operations in horizontal wells. The technology is being attempted throughout

South America, the Middle East, and Southeast Asia. Several UBO projects have also been

completed in Africa, Australia, and Europe. Underbalanced operations were introduced to the

offshore environment by Shell in the late 1990s.

5

Chapter 2: Literature Survey

2.1 Underbalanced Operations

The following underbalanced operations are widely in practice worldwide and they provide

the significant advantages as well.

2.1.1 Underbalanced Drilling

Underbalanced operation has the following benefits. Each of these benefits is discussed in

detail.

Fig 2.1 Conventional Overbalanced Vs Underbalanced Operations [Babajan S. et al., 2009].

Increased rate of penetration: While drilling conventionally in an overbalanced state, the

hydrostatic pressure of the drilling fluid exerts a force against the rock that is being penetrated,

6

thus requiring more energy to remove the rock. At the same time, a filter cake is deposited due to

spurt loss of drilling fluid. The bit cutters must remove this deposit along the formation being

penetrated thus the type of drill solids and total content of solids in fluid system impact

penetration rate. The sub-micron particles are the biggest culprit, not the larger particles.

Conventional drilling is a process of grinding where re-circulated drill solids that are not

removed by the solids control equipment are re-introduced into the wellbore and subjected to

regrinding. Reducing the micron size of the drilling fluid constituents into colloidal.

In UBD operation, there is no pressure on the rock to hold the solids in place and cause the

deposition of filter cake. Since the UBD fluid is free of solids, they cannot be reintroduced into

the circulation system for re-grinding. Furthermore, since the formation pressure is greater than

the wellbore pressure, less energy is expended in breaking the rock, and results in extraordinarily

high rates of penetration. Increases of penetration by a factor of ten with respect to conventional

drilling are not uncommon while drilling underbalanced as compared with conventional drilling.

A UBD Project done by The Exxon/Mobil PASE showed an average increase in penetration rate

from 6 feet per hour, when drilled conventionally, to 27 feet per hour, when drilled

underbalanced through the fractured basement production zone. Underbalanced drilling has

produced marked improvement in improvements in both ROP and overall drilling time in the

Hassi Messaoud field [Moore D.D. et al., 2004].

Improved formation evaluation: Another significant advantage of UB Operation is that it

allows continuous reservoir evaluation and characterization. While production characteristics,

such as fluid types, flow rates, and pressures can be identified, reservoir parameters such as static

pressures can also be estimated while drilling underbalanced. Further, formation fractures and

the resulting flow/pressures may be identified during UBO. Underbalanced conditions allow

formation fluids to flow into the wellbore under a negative pressure differential, and therefore

allow detection at the surface that would otherwise be masked by an overbalanced state. A

marked increase in flow rate from the well detects the presence of a formation. When

conventional fluids are used, there are several factors that need to be considered to ensure that

subsurface geological information can be properly evaluated, such as; salinity of the mud, filtrate

7

invasion depth, pressure-induced fractures caused by the fluid and type-base fluid (chemistry) of

the system.

The rock cuttings during drilling operation or geological specimen are subjected to mechanical

fluid agitation during its travel up the wellbore. This action, in conjunction with the chemical

effects of the drilling fluid results in sample deterioration. Because overbalanced conditions

prevent inflow from the formation, a possible zone of consideration could be overlooked. During

underbalanced drilling, all of the above drilling fluid characteristics disappear.

Increased productivity/ reduced formation damage: Increased productivity from a reservoir is

perhaps the most important advantage of UB Operations. Conventional techniques that employ

weighted muds can create a large overbalance pressure between the wellbore and reservoir. This

overbalance can result in the invasion of contaminants like drilled solids and foreign fluids into

the formation. Subsequently, this overbalance causes significant reservoir impairment, and

reduced productivity, thus requiring further costly stimulation jobs. By the definition of

underbalanced operations, these problems are prevented if the operation stays in an

underbalanced state. If the drilling fluid causes no damage, as is usually the case with

underbalanced drilling, the probability of stimulation is reduced or eleminated.

The remediation of formation damage requires costly well stimulation techniques such as

acidizing and fracturing. Formation damage is of particular concern when drilling high-angle and

horizontal wells where reservoirs are exposed to an overbalance of drilling fluids and solids for a

considerable length of time. By employing underbalanced drilling operation techniques, fluid or

solid invasion can be minimized, or in some cases eliminated, thereby reducing formation

damage and maximizing well productivity. The extent of formation damage is measured through

skin factor.

The productivity index for a vertical well is:

Eq. (2.1)

8

The productivity index for a horizontal well is:

Eq. (2.2)

The relation between PI and drawdown is:

Eq. (2.3)

During underbalanced operation generally filter cake does not buildup, due to negligible drill

solid accumulation. Therefore, depth of fluid penetration may be deeper if overbalanced

conditions occur during underbalanced operation. If the formation is sensitive to damage from

the liquid phase, damage can be more severe than that caused by conventional procedure.

Therefore, careful planning is necessary while operating underbalanced.

Fluid compatibility as well as proper modeling of down hole pressure before underbalanced

operation is important to prevent production hindrance. If modeling is not conducted, there is a

strong possibility for occurrence overbalanced conditions in the reservoir. Figure 2.2 illustrates

pseudo-steady-state depletion condition near well bore region during underbalanced operation.

Figure 2.3 shows the invasion mechanism during reduced underbalanced/overbalanced

condition. The gravity induced invasion in underbalanced drilling operations through macro

fractures in horizontal well operations is depicted in Figure 2.4.

9

Fig. 2.2 Pseudo-steady-state depletion condition near well bore region during underbalanced

drilling condition

Fig 2.3 Invasion during an overbalanced/reduced underbalanced condition phase in the near

wellbore depletion region

10

Fig 2.4.Source: The JCPT September 98, volume 37, page 48.

Minimized loss of circulation: Loss of circulation is defined as the loss of mud in quantity to

the formation during any oil field operation. This loss occurs when the hydrostatic pressure of

the drilling fluid exceeds the fracture gradient of the formation. The openings in the formation

are about three times as large as the largest particles in the fluid used for operations. Due to the

nature of conventional fluids, loss of circulation is a constant risk. As long as an underbalanced

state is maintained, there is no loss in circulation. However, it may happen in special cases, such

as water flows, due to the formation of mud rings and subsequent packing off or due to poor hole

cleaning of the formation.

11

Fig 2.5 Fluid loss and solid loss in overbalanced/underbalanced operations [Bennion D.B., 2002]

In severely depleted reservoirs with high permeability and deepwater marine risers, loss of

circulation is a serious problem with overbalanced systems. In these cases, the ability to remove

12

cutting solids from the wellbore is lost. If pore spaces are not large enough to take the cutting

solids, solid buildup takes place and finally results in the mechanical sticking of the drill string.

For this reason, severely depleted fields or under-pressured reservoirs cannot be operated with

conventional fluids. The Exxon/Mobil ARUN field is an example of how to drill a severely

depleted formation underbalanced. This field could not have been drilled conventionally.

Elimination of differential sticking: During the oil field operations when the drill string is in

the center within a wellbore, the hydrostatic pressure exerted on the drill string is equal in all

directions. But when the drill string comes in contact with the wall cake opposite a permeable

formation zone of lesser pore pressure, the drill string can get stuck to the wall cake against the

wall of the hole due to pressure difference. The hydraulic force then acts across the isolated

portion of the drill string squeezing of wall cake occurs, holding the string in place. For every

square inch isolated by the cake, there is a confining force of hydrostatic differential pressure

known as the mechanism of differential sticking. In conventional operation, all the necessary

ingredients are always present, and always a possibility of differential sticking. With

underbalanced drilling operation, there is no hydrostatic pressure differential to the formation

and no filter cake. It is impossible to get differentially stuck while drilling underbalanced.

Increased bit life: Due to the friction at the bit a considerable amount of heat is generated

between the drill strings and wellbore. The circulating drilling fluid transports heat away from

these frictional regimes through convection. It should be noted that the solids in the drilling fluid

contribute to additional frictional heat generated at the bit; the higher the inert solid content, the

more heat that is generated. Transportation of heat away from the bit is more efficient in

underbalanced operations because there is no additional force holding the formation in place

(less frictional force), the bit does less work to cut the formation. By using UBD operation, the

fraction of retained solids is maintained at a minimum value, depending if a one-way process is

used or a closed-loop system is employed. UBD also requires less weight on the bit to obtain

optimum ROP. In this way underbalanced operations improves bit life.

13

Reduction of expensive drilling fluid: Conventional drilling fluids are having many costly

additives that are added to control fluid properties such as viscosity and fluid loss. As in the case

of loss circulation zones, additional chemicals and sized particles are added to control losses.

These fluid systems may be very costly. Simple fluids such as, KCl water or produced oil are

typically used in UBO, costly drilling fluid programs can be eliminated for the hole section

drilled in an underbalanced state. Significant expenditure savings may be realized by not losing

expensive drilling fluids to the formation. During conventional operation, the well is designed

such that reservoir fluids do not enter the wellbore during drilling operations. If reservoir fluids

enter the wellbore, the system relies on personnel to recognize the inflow and control the well

pressures correctly to remove the formation fluids from the system. Most blowouts occur, not

because of poor engineering or planning, but due to failure of personnel to correctly recognize an

inflow and properly handle it.

Improved safety and reduced environmental impact: Conventional oil field operational fluids

are heterogeneous mixtures of organic, inorganic, and inert substances. The composition is

variable that dictates the level of toxicity of the fluid. The efficiency of the solids removal

equipment is necessary to continue the dilution to maintain a usable fluid. As an example, for

every incorporated barrel of drilled solids a nineteen-barrel dilution is required to maintain a

five-percent total active drill solid content that is considered to be the upper limit in a water-

based drilling fluid. While UBO requires naturally occurring fluids such as gas and water, when

gas, mist, and gasified fluid systems are applied. In some cases a corrosion inhibitor is required

or it may be coated on the drill-string or in both forms. Drilling with foam fluid system requires

the addition of surfactants and defoamers. The chemical concentration of the additives are very

low (ppm) and normally of a non-toxic nature. The majority of surfactants used for foaming

agents are biodegradable so that having less impact on environment. As gas is the larger

component, very little waste is generated as compared to conventional oil field operational

fluids. Therefore disposal problems are minimized when considering volume and toxicity. A

properly designed UBO system is less reliant on personnel recognizing an accidental event. The

system is designed to safely handle a continuous inflow from the formation. Underbalanced

14

operation systems also give a continuous positive BHP reading throughout the operation leads in

to improved safety.

At present Petroleum Development Oman a joint venture of Shell is carrying on underbalanced

drilling programs for more complex UBD multi-lateral in south Omani fields. In the first or pilot

phase, PDO drilled 14 wells underbalanced in the Nimr field in Southern Oman.

Future of Underbalanced Operations is a young progressing game-changing technology

developed in response to the oil & gas industry needs to control project cost while enhancing

productivity. Underbalanced operation challenges the tradition-bound operating procedures the

industry had used for more than half a century. Even though, underbalanced operations (UBO) is

getting more and more popular in the world. The main reason is that its advantages can meet

requirements of current world petroleum exploration and production situation. The world Oil &

Gas industry quickly saw the advantages of underbalanced drilling, and the technology is now

employed where the geology and reservoir are suitable. Soon, UB operations will become the

standard field development technique, both onshore and offshore [Babajan S. et al., 2009].

2.1.2 Underbalanced perforation

Every cased well must be perforated so that fluids can flow from subsurface zones or be injected

down hole. Optimizing production or injection requires careful design, pre-job planning and field

implementation to obtain clean conductive perforation that extend beyond formation damage into

unaltered reservoir rock. During, explosive perforating it pulverizes formation rock grains, which

causes a low permeability crushed zone in the formation and creating the strength for migration

of fine particles. This process also leaves some detonation debris inside the perforated pathway.

Underbalanced pressure is the most widely accepted technique for optimizing perforated

completions. In this method wellbore pressure before perforating is less than the adjacent

formation pressure before perforating. The study suggests that surge flow from a reduction in

near-wellbore pore pressure mitigates crushed –zone damage and sweeps some or all of the

debris from the perforated tunnels.

15

In 1970s, completion engineers recognized the potential of underbalanced pressure for improving

perforated completions. During the 1980s and 1990s researches confirmed that a high static

pressure differential between wellbore and formation often yielded more effective perforations.

The study concluded that rapid fluid influx was responsible for perforation cleanup and

recommended for general underbalanced perforating criteria [Johnson A.A. et al., 2003].

Schlumberger scientists analyzed transient perforating pressure during laboratory tests and found

that static underbalance alone does not ensure clean perforations. Results indicate that previously

neglected fluctuations in wellbore pressure immediately after shaped charges detonate, not the

initial pressure differential, actually govern perforation cleanup. This improved understanding of

dynamic wellbore pressure to develop the patented PURE Perforating for Ultimate Reservoir

Exploitation process [Brooks J.E. et al., 2003]. In 1989, researchers calculated underbalanced

pressures in gas wells based on sand- production potential determined from sonic logs [Crawford

H.R., 1989]. The author combined new data with data from the prior Amoco project to develop

equations for the minimum underbalance required to eliminate the need for acid stimulation

[Tariq S.M., 1990]. Another study indicates that flow and surging after perforating are less

critical in damage removal, but might sweep debris and fines into the wellbore [Hsia T.Y. et al.,

1991].

Dynamic underbalanced perforating is applied by Anadarko Petroleum Corporation in the Brady

gas field of Wyoming. In addition to high concentrations of hydrogen sulfide, the weber

formation comprises about 600ft (183m) of inter-bedded sand, shale and dolomite stringers.

Permeability ranges from 0.5 to 1.5 mD with a current reservoir pressure of less than 2800 psi

(19.3 MPa) at 14000ft (4267m).The 18 existing well completions in this field used wireline-

conveyed guns and static overbalanced perforating techniques, which resulted in minimal flow.

Anadarko performed perforation- wash treatments using hydrochloric-hydrofluoric acid to make

a commercial production. After acidizing, these wells typically flowed 1to5 MMcf/D (28640 to

143200 cubic meter/day). Three of the wells required fracture stimulations. Anadarko chose the

PURE perforating technique to recomplete the Brady 38 W well in an upper section of the Weber

formation [Stutz H.L. et al., 2004].

16

Dynamic underbalanced perforating provides a successful completion without additional

stimulation. A pre job NODAL production system analysis for the same indicated that the well

should produce about 3.85MMcf/D (110,260 cubic meter/day) without any formation damage.

However, completion skin enhanced 20 after perforating overbalanced and before acidizing. The

PURE technique achieved a sustained flow rate of 5.2MMcf/D (148,930 cubic meter/day) just

hours after perforating with an initial 3250-psi (22.4-MPa) overbalance .The estimated

perforation skin was negative 1.17, or slightly stimulated. Later in 2002, Anadarko drilled the

56W well after the success of the Brady 38W recompletion convinced Anadarko to use the

PURE technique again. Both wells used permanent TCP completions. An innovative completion

method has been used to complete two oil fields in the central and northern areas of the North

Sea. The Skua field was a single well development high-pressure/high temperature (HP/HT) with

a reservoir pressure of 9350 psi and reservoir temperature of 307°F. The Penguin field is a 4-well

development with an average reservoir pressure of 8000 psi and reservoir temperature of 265°F.

Each sub-sea well required a long horizontal section to maximize production from the tight,

highly compartmentalized reservoirs [Martin B. et al., 2002].

A new gun deployment system based on production packer technology is chosen because it

appears to meet all the well requirements. The polished bore receptacle (PBR) and hydraulic set

permanent packer has been designed with the guns hung off the seal assembly of the PBR. The

system also allows the tubing conveyed perforating (TCP) guns to recover if they failed to fire or

malfunction. The Skua and Penguin wells are completed with a fully cemented liner. By using

this completion method and TCP guns, the wells are successfully completed and perforated

underbalanced in a single trip. A slickline plug is set in the nipple below packer, and the tubing

pressure is tested to 5000 psi to set the packer. After the retrieving the plug, the packer is tested

from above and below. Tubing hanger plugs is set, and the blowout preventer (BOP) stack is

retrieved. The Xmas tree is run and tested, and the tubing-hanger plug is retrieved. The TCP gun

firing head is deployed on slickline, and the well is perforated at 500-psi underbalance with time-

delay initiation [Martin B. et al., 2002].

17

The Etive/Rannoch reservoirs are located at a depth of approximately 11,400 to 11,500 ft

TVDSS, 14150 to 20300 ft AHD and are accessed with a 1200 to 4600 ft horizontal section. The

average reservoir pressure is 8000 psi and reservoir temperature is 265° F. The wells are shut in

until all four wells are completed. The production is by natural depletion drive via a flow line to

the platform. Optimum perforating performance is achieved by subjecting the entire interval to

an underbalance. The impact for one of the wells has been modeled for 5 mD and 10mD for 20-

in. penetration. The result shows the benefits of the underbalance, when the permeability is low,

the optimum underbalance of approximately 2000 psi. is achieved [Martin B. et al., 2002].

The following underbalanced pressure differential has been recommended by [Crawford H.R.,

1989] to achieve “clean” perforations in oil wells:

Eq. 2.4 2.1.3 Underbalanced Workover

If a well is drilled underbalanced then killed and completed overbalanced .the original purpose of

drilling underbalance is defeated .Ideally ,the well must be completed underbalance to prevent

/minimize formation damage , thereby maximizing productivity .

Snubbing system: If tripping is to be conducted underbalanced; a snubbing system will be

installed on top of the rotating control head system. The current systems used for offshore

workover operations are so called rig assist snubbing systems. A jack with a 10ft stroke is used

to push pipe into the hole or to trip pipe out of the hole. Once the weight of the string exceeds the

upward force of the well, the snubbing system is switched to standby and the pipe is tripped in

the hole using the drawworks. The ability to install a snubbing system below the rig floor allows

the rig floor to be used in the conventional drilling way. The snubbing system is so called rig

assist unit. This unit needs the rig drawworks to pull and run pipe. It is designed to deal only

with light pipe situations.

18

Fig. 2.6 Snubbing System (Source: www.istockphoto.com/file_closeup/industry/heavy-

industry/4434253)

Following are the method adopted for completions:

Open hole completion: It is a commonplace practice, presently to have underbalanced

completions in the form of simple openhole / barefoot completions, where producing interval is

left uncased openhole completions offer advantages of simplicity, low cost and less maintenance.

However, the openhole completion method is limited to well consolidated formations.

These disadvantages are as long term borehole stability is questionable and the well may get

impaired by the production of unwanted fluids (gas or water). The final completion string is

lowered in the openhole by one of the following methods:

a) After balancing the reservoir pressure with a compatible, clean solids free completion fluid or

with formation fluids which is allowed to flow into wellbore.

b) Snubbing unit can be deployed to run in jointed completion string, under pressure without

subducing the well.

19

c) Well can be completed with coiled tubing as final completion string, using coiled tubing unit.

Cased hole completion: In most cases liner / casing is lowered after subduing the well with

clean fluids. Alternatively, the following techniques can be adapted to lower liner/casing,

underbalanced conditions:

a) Snubbing unit can be used to lower liner /casing in under pressure, with out killing the well.

However main disadvantage compared to conventional drilling rig, is slower tripping speed.

b) Downhole lubricator: This technique involves the use of inflatable bridge plug as a temporary

barrier to prevent flow. After drilling open hole section of the well underbalanced , an inflatable

bridge plug is the run (on electric or coiled tubing) and set in the intermediate casing at a depth

that will allow accommodating the complete liner string above it. The intermediate casing now

acts as a subsurface lubricator; the liner is then run into the hole with a standard type J-overshot

attached to the bottom. After liner string is run in, the rotating BOP is closed around the running

string .When the liner comes in contact with the inflatable bridge plug, the inflatable bridge plug

is engaged and released by the overshot. After packing elements have relaxed, the liner is run to

the depth. The inflatable bridge plug and the overshot are left in hole. In the above two cases, if

casing /liner is required to be cemented, the well would need to be subdued, thereby sacrificing

underbalanced conditions. Foam cementation technique may be adopted to minimize formation

damage.

20

2.2 Underbalanced Fluid System and Techniques

2.2.1 Selection of an underbalance operations fluid

Selection of an underbalanced fluid operation is performed on the basis of Reservoir

characteristics like formation type (such as sand, limestone, and clay), pore pressure,

characteristics of reservoir fluids, reservoir permeability, rock matrix porosity, well geometry

includes directional characteristics and hole size, environmental issues are also taken care during

the selection of UB fluids for cuttings disposal and disposal of fluids because the early

production during the operation, well test data, production history & drilling reports of the offset

wells are also taken in to knowledge prior for selecting the fluid

2.2.2 Underbalanced operational fluid design aspects

The primary concern for underbalanced operational fluid design includes as like the fluid design

for conventionally operated wells, which are for bringing the cuttings to surface, cooling and

lubrication of the bottom hole assembly and to control the bottom hole pressure. UBO fluid

system design is one of the most overlooked parts of underbalanced projects. While designing an

underbalanced fluid system the impact on the desired equivalent circulating density must be

considered. The equivalent circulation density is a combination of annular fluid density,

frictional pressure loss in the annulus, and surface chock pressure. The design must result in a

pressure that is below the formation pressure without creating any wellbore stability or excess

production during the operation. Compatibility between the components of the fluid system to

the rock matrix components of the formation, the fluid system compatibility with produced fluids

incompatibility will lead into entire objective of underbalanced operations.

Hole cleaning is a very critical factor in designing the fluid for any underbalanced wells. Most

underbalanced fluid systems prefer the velocity of the fluids to the viscosity for cleaning the

hole. Cuttings carrying capacity is better in foam fluids compared to the pure gaseous fluids.

21

Temperature stability of fluid constituents must also be considered in designing an

underbalanced fluid system. Many of the chemicals like surfactants and viscofying agents may

break down with high temperatures or its effectiveness is negligible. It will also affect the density

of the fluids used in designing the system. With increase of Temperature density of used

chemicals falls down.

Corrosion factor is also plays significant role while designing a fluid for underbalanced

operations. The injected fluids should contain the anti corrosive chemicals or the equipment and

other down hole assemblies should contain the protective film layer during gaseous operations.

Due to the production during operations the H2S and other gases improves the corrosion rate

which leads to the sulfide stress cracking of down hole equipment’s materials. The efficiency of

the downhole equipment should not be decrease when using the multiphase fluids. The fluid with

elastomers can affect the functionality and longevity of the mud motors and downhole measuring

devices. Downhole tools (such as tools with no elastomers) should be selected that will not be

effected by the fluid. The fluid selected should be able to transmit data from downhole. Gas is a

compressible fluid; if gas is used in the fluid system, it may dampen or eliminate any signal

transmitted downhole.

Health, safety and environmental must be considered in selecting an underbalanced fluid system.

The points in consideration are handling of fluid at surface and disposal of return fluids,

produced fluids and solids. The return fluid may contain various toxic contaminants.

22

2.2.3 Fluid system selection

Underbalanced fluid systems have been categorized by the IADC by the following system:

Table 1- IADC fluid classification

Fluid System Specific Gravity Equivalent Mud Weight (ppg)

Classification Level

Gas Drilling 0-0.02 0-0.02 1 Mist Drilling 0.02-0.07 0.2-0.6 2 Foam Drilling 0.07-0.6 0.6-5 3 Gasified Liquid drilling

0.55-0.9 4.5-7.5 4

Liquid drilling 0.8 and >0.8 6.9 and >6.9 5

The fluid system selected for a particular project is dependent on the desired BHP, tolerance to

water influx, hole cleaning, cost and environmental consideration. Fluid system used in

underbalanced operations mentioned in Table 1 will be discussed in details in the next section.

2.2.3.1 Gasified (aerated) fluid operations

In this type of fluid operations gas and liquid phases have been intentionally mixed to decrease

the density of the fluid. The gas (mostly air or nitrogen) is introduced into the fluid at the surface

before it enters the drill pipe or it is introduced downhole into the liquid at the annulus. For

safety concern natural gas (primarily methane) has also been used to gasify fluids in place of air

or nitrogen. As per the well fluid design as well as feasibility aspects any liquid (oil, water/salty

water etc.) may be used for the operation.

In general., the selected fluid system is easily separated into its constituent phases the system

reaches the surface once. Various flow regimes is shown below for a horizontal well operation.

23

Fig.2.7 Various flow regimes in horizontal wells during gasified (aerated) fluid operation

[Ghalambor A. et al., 2004].

Gasified fluids are optimized to clean the hole and maintain the BHP below the pore pressure

and above the wellbore-stability pressure. Proper hole cleaning, pressure maintenance as well as

keeping the entire fluid system together are mandatory requirement for successful underbalanced

operation. Viscosities, gel strength, velocity act and other forces act in the annulus to maintain

fluid stability with gasified fluids. In UB operations, the pressure will make the greatest impact

on the gas properties. Because of the compressibility of the gas phase, the gas content of the

fluid, as measured by volume, changes with temperature and pressure.

One fact is that if the gas/liquid mixture reaches about 5,000 ft of vertical depth (it may vary

with other pressure and downhole conditions), no significant compression takes place. This depth

is called “depth of effective compression” and is particular for each gas. The introduction of gas

24

to a system below the depth of effective compression does not help in the UB operation. Gas

may be injected through other ways like parasite string, concentric string or by drill pipe.

Fig.2.8 Compression of the fluid at different depths in a wellbore decreases hydrostatic pressure

disproportionately, after [Medley G.H.et al., 1998]

The amount of gas in the fluid at any point, measured by volume, can be expressed as foam

quality or as fluid ratio. Ratio R (% by volume of gas) is the ratio of gas to liquid unit under

existing conditions of pressure and temperature. A good rule of thumb for a gasified fluid is to

try to maintain the ratio through the system at 5:1 to 40:1 (i.e., 80 %< foam quality < 97.5 %).

Merits of Gasified System: The gasified system has various merits which include avoiding lost

circulation, to reduce formation damage, to avoid differential sticking and, to increase the rate of

penetration. Lost circulation is the main reason for using gasified fluids (Fig.2.9). The

introduction of gas into the system makes the fluid column lighter by replacing some of the mud

with gas. In such case the flow is from lost circulation zones to within the well bore.

25

Fig. 2.9 Gasified mud injection reduces BHP, after [Rehm B., 2002].

If the hydrostatic pressure of mud in the wellbore is greater than formation pressure, the mud

invades in to the reservoir pores reduces the permeability of reservoir rock near the wellbore

(Fig. 2.10).Underbalanced operations allow fluids from the reservoir to flow into the borehole.

Gasified systems prevent filter cake and filtrates from entering the formation.

Fig.2.10 Formation damage reduction in gasified systems (a) Hydrostatic overbalance leads to

formation damage. (b) Reduction in pressure by gas injection prevents formation damage, after

[Rehm B., 2002].

26

When the fluid column exerts more pressure than the formation fluid then due to the differential

pressure sticking can occur. Due to the higher pressure the pipe tends to move towards the

formation rather than being it in the center of well bore and finally got stuck up. (Fig.2.11). If the

well is operated underbalanced, flow is from the formation into the wellbore. Thus it does not

build up filter cake so that eliminates the possibility of differential sticking.

Fig.2.11 Differential sticking results from higher pressure exerted by mud than the formation

fluids, after [Rehm B., 2002].

Increased rate of penetration is also a merit of gasified fluid operation. ROP depends on many

factors like bit weight, rotary speed, jet impact, hydraulic horsepower, rock strength, and chip

hold-down force. When fluid column pressure is greater than the pore pressure in the rock, the

overbalance holds the rock chip cut by the bit in the wellbore. With gasified fluid column during

UBO, the pore pressure is greater than mud-column pressure. This lighter column allows the

formation cuttings to flow up the system. This leads in to easy and quick removal of cuttings and

results in higher rate of penetration.

27

Fig 2.12 ROP decreases as BHP increases, after [Rehm B., 2002].

Barriers in the gasified system: The biggest problem with a gasified system is the

discontinuous nature of the operations. Whenever any tripping or any problem within the

wellbore happens due to some technical reasons, the gasified fluid begins to separate, mainly in

the annulus. Once the circulation is re-established, the resultant slugs of liquid without any gas

can exert higher hydrostatic pressure downhole in the formation that may exceed the reservoir

pore pressure (Fig.2.13).

Fig 2.13: Inconsistent pressure in UBO, after [Medley G.H.et al., 1998].

28

Several techniques are used to overcome this problem due to the slug effect, creating gas slugs to

counteract them. The formation will initially feel the effects of only the gas-phase hydrostatic

pressure when circulation is restarted (Fig.2.14).

Fig.2.14 BHP remains much more constant with gas circulation before connections, after

[Medley G.H.et al., 1998]

Special equipment has been designed to carry a gasified fluid in the annulus or in a portion of the

drillstring and part of the annulus, rather than circulating the gas phase all the way from the

surface to total depth and back again [Medley G.H.et al., 1998].

29

Parasite strings: It is a permanent or temporary tubular string connected to one of the casing

strings near the bottom (but above the float collar) in the wellbore. A parasite string will allow

for the introduction of gas into the annulus between the two (Fig. 2.15). Gas is injected into the

tubing string at the surface and enters in the fluid system near the bottom of the surface pipe at a

depth 2500ft -3000ft.

Fig.2.15 Parasite tubing string, after [Medley G.H.et al., 1998]

Concentric string: It is like as a casing string which is run into a wellbore and temporary hung

off in a special wellhead, it is concentric to the casing (Fig.2.16).Gas is injected into the annulus

between the two strings, gas comes out from the bottom part of the concentric string. The point is

termed as injection point.

30

Fig. 2.16 Concentric casing string, after [Rehm B., 2002].

2.2.3.2 Foam fluid operations

Foam systems are created when water and gas are mixed with a surfactant. The structure of foam

is made up of bubbles of gas surrounded by a liquid film. A surfactant or foaming agent, in the

liquid phase stabilizes the films that form the bubble walls, which allow the foam structure to

persist. Foam has normally composition of about 97% gas and only about 3% liquid at surface

conditions (Fig.2.17).

31

Fig. 2.17 Foam is made of bubbles that are surrounded by a liquid film, after [Rehm B., 2002].

Two basic types of foam are used in UB operations [Rehm B., 2002 and Medley G.H.et

al.,1998]. Stable foam is made off a surfactant as a binder and stiff foam. Stiff foam is built by

using surfactant, bentonite, polymers and using any gas. Air is most frequently used in foam

fluid operations. Other gases, such as nitrogen, natural gas, or carbon dioxide, can be also used

instead of air. Occurrence of hydrogen sulfide or any other low Ph acid gases makes counter

effect on the foam stability. The most common used fluid is fresh water. Freshwater-based foam

will be feasible. The only way freshwater will cause foam to deteriorate is when the foam quality

is very low. Brine can also be used to generate foam with specific surfactants. Oil is seldom used

as the base liquid for foam fluid. The hydrocarbon contaminants decrease the effectiveness of

foam.

Cutting carrying capacity as well as hole cleaning is better with foam fluids compared to the

other fluid system. The high effective viscosity of foam provides the good transportation mode to

the cuttings from down hole to the surface. Any size cutting generated at the bit can be brought

out of the hole with foam. Even when circulation stops, the foam will continue to expand for a

while and carry on lifting the cuttings.

Bubbles

Liquid films

32

Fig. 2.18 Large cutting cleaning in foam drilling operations, after [Medley G.H.et al., 1998].

Foam Quality:

Quality of foam is defined by the ratio of gas to liquid. Quality of foam is the percentage of gas

in the foam at a specific depth or pressure. For example, 70% quality foam contains 70% gas by

volume, while 85% quality foam contains 85% gas by volume. Foam with a quality of 65%

means it is 65% gas and 35 % water. The same foam deeper in the hole might have a quality of

only 60% because increased pressure compresses the gas. Therefore, foam quality varies with

hole depth.

As the quality of the foam (ratio of gas to liquid) increases, the carrying capacity of foam also

increases. Good foam has foam quality between 55% and 96%. This keeps the foam stable. If the

foam quality exceeds about 97%, the fluid undergoes a two-phase fluid having gas as the

continuous phase. This is called a mist fluid (Fig.2.19).

Large cuttings

33

Fig.2.19 Difference in phases between foam and a mist system, after [Medley G.H.et al., 1998].

Foam composition: Foam is usually made up locally because what works in a particular well in

one area may not work in another. Once the optimum ratios of gas and liquid have been decided

on, the elements that must be mixed together to form the liquid phase should be determined. The

other constituents are caustic soda, soda ash, foaming agent and corrosion inhibitor.

Advantages of foam fluid operation: The advantages with the foam fluid operations are generally

the primary benefits with the underbalanced operations. Foam systems are among the best

underbalanced lost-circulation fluids. As being a light fluid, foam has a major advantage in

avoiding lost circulation (Fig.2.20). As the flow is from the formation to the wellbore due to less

BHP. The small bubbles of the foam system that enter in to the lost circulation zone, slightly

expand, and plug the zone. Reduction of lost circulation is enhanced without creating any

damage to the reservoir as there is not any solid plugging

Foam fluid operation avoids the reservoir damage. Almost every conventional fluid system

damages the reservoir near the wellbore. The best way of performing the operation is when flow

comes from the reservoir into the borehole and does not push filter cake solids and filtrate into

the formation. For reservoir protection the casing may set up at the upper part and then drill the

reservoir UB with a clear, non-damaging fluid or non-invasive foam.

34

Fig.2.20 Foams reduces BHP, avoiding lost circulation, after [Rehm B., 2002].

Fig. 2.21 Foams minimize reservoir damage because flow is from the reservoir to the wellbore,

after [Rehm B., 2002].

Foam fluid system avoids differential sticking. Differential sticking occurs when the drill pipe or

drill collars lie against the side of the hole and pressure in the hole is higher than pressure in the

35

formation. The possibility of sticking in deviated holes is more. If the pipe becomes stationary

for any reason, it can become stuck. Forces required for removal of sticking depends on the

contact area of the pipe with the filter cake. The solutions to differential sticking include the use

of oil mud. The best solution is not to allow differential sticking conditions to exist. If the well is

operated underbalanced, flow is from the formation into the wellbore and filter cake and filtrate

do not exist. Foam contains very less constituents. The constituents have not any such properties

which cause any stuck pipe phenomenon (Fig.2.22).

Fig.2.22 In UB Operations with foam, reservoir pressure is higher than wellbore pressure. Thus,

differential pressure sticking cannot occur, after [Rehm B., 2002].

Foam fluid operation increases drilling rate. Generally, the drilling rate increases as hydrostatic

pressure decreases. The foams can provide faster overall penetration rates. Cuttings and fluid

removal will be more efficient, allowing higher ROP. A major effect on drilling rate is cuttings

removal, which is determined by chip hold-down force. In UBO pore pressure is greater than

36

fluid column pressure. The lighter mud column pressure allows the bit cuttings to explode under

the bit, and the lifting characteristic of the foam quickly sweeps the bit cuttings away.

Hole-cleaning problems are minimized by using the foam fluid system. The system has excellant

cuttings transportation property. Foam lifts the cuttings and carries them with very little slip.

Foam can clean a hole with small liquid volumes and low annular velocities. The foam system

also holds cuttings in suspension when circulation is stopped.

Foam fluid system has its own merits which have been described earlier. The system has also

few limitations which are hindrances in making it successful operations among all the fluid

systems.

Corrosion may be controlled is rather than being a permanent limitation to foam fluid operations.

A corrosion inhibitor is used to the injected liquid to control the corrosion rate; slow corrosion of

downhole equipment is permissible until its function should not be affected by any formation

fluid inflows that might occur. Corrosion problems with foam increase with increasing depth

with increase in temperature.

Wellbore instability is another limitation with foam fluid operations. The instability may be

cause by mechanical or chemical reasons. To overcome this limitation foam should have a lower

tendency to erode the borehole wall. Erosion is due to reduction in shear stress of the well bore

boundary naturally fractured formations. This occurs because foams are efficient at cuttings

transport at low annular velocities. Foam used for the operation should have high viscosity at low

shear rate. The foam fluids are having higher bore hole pressure in comparison to created by gas

or mist fluids. This will decrease the difference between circumferential stress and borehole

pressure without providing the support to wellbore so this will lead to mechanical instability in

weak rock. During the foam fluid operation formation fluid and formation water influx happens.

They alter the foam composition and leads to chemical instability of the system.

Downhole fires occurrence with this system are also a limitation. The limitation is due to the

separation of air and foam in horizontal or deviated wells. As low annular velocities are used in

37

foam fluid operations, gravity induced separation may occur forming air as a continuous phase at

the upper part of the hole. Which increases the possibility of down hole fire in such conditions.

Foam disposal is also a major concern with using foam fluid operations. The cost of handling

and disposing the foams is an extra addition with this fluid system. There are several developed

methods of defoaming systems. Even if the foam, water, and chemicals are not reused, these

defoaming methods are termed recyclable foam systems.

2.2.3.3 Mist fluid operations

Mist Fluid System Operations refers to those operations where the drilling fluid is a combination

of gas with a small ratio of water. For a mist system, the gas is the continuous fluid with liquid

bubbles dispersed in the gas. Mist is formed if the liquid volume fraction is less than 2.5% water

at the current pressure and temperature (Fig.2.23).

Fig.2.23 Mist formed by water drops in suspension.

The mist fluid operation is performed by creating the mist which consists; a small quantity of

water treated with a foaming agent is injected into the compressed air flow. Any produced water

should also disperse in to mist. Mist fluid move at approximately the same velocity as the gas. If

an important water inflow is encountered, the liquid volume fraction downhole can increase to a

38

level where foam is formed. During mist operations hydraulics is important for cleaning the hole.

High velocities of gas is required for proper hole cleaning because in mist flow gas have the

continuous phase which is less efficient for lifting cuttings compared to liquid as continuous

phase. For fluids to lift cuttings have some viscosity compared to lesser viscosity. For better hole

cleaning the volume rate of gas circulated through a wellbore is generally based upon three hole-

cleaning criteria.

Minimum energy criteria depicts that a certain minimum kinetic energy is required to lift a

cutting of a given size [Ghalambor A. et al., 2004]. The same minimum kinetic energy must be

maintained throughout the wellbore to lift the cuttings out of the hole. This is simple among all

methods implemented for lifting the cuttings. Terminal velocity criteria explains that the

minimum velocity of gas has to be greater than the terminal velocity (or slip velocity) of the

cuttings to bring them out [Ghalambor A. et al., 2004]. This method describes only the minimum

rate of gas required to lift the cuttings. Minimum BHP criteria explain that the maximum hole

cleaning and the maximum penetration rate can be achieved when the BHP is minimum

[Ghalambor A. et al., 2004].

Although mist fluid operations have various advantages yet it has its own particular limitations.

These limitations are like air compression requirement. Mist fluid operation requires air injection

rates 30% higher than as required for dry-air operations at the same depth and penetration rate.

The higher air requirement leads in more work for compressors so that high fuel consumption for

the additional work by compressor. Waste water and other additives disposal give additional cost

to the whole operation.

In mist fluid operations the gas flow rate tends to be higher and the density of the circulation

fluid is greater than it is for dry-air drilling. These factors increase the potential for wellbore

erosion if weak or poorly consolidated formations are penetrated. Chemical instability of

wellbore is another limitation with the mist fluid operation. Instability occurs when water-

sensitive shales are encountered during the aqueous phase in the mist fluid. Hydration and

swelling of shales creates irregular cutting and create hindrance in the operations. Swelling may

39

be reduced by the addition of salts, such as potassium chloride (KCl), to the injected water

[Economides M. J. et al., 2000].

There is a significant possibility of corrosion to downhole equipment during mist fluid

operations. The high oxygen concentration present in the aqueous phase promotes corrosion of

exposed steel of downhole equipment. An appropriate corrosion inhibitor is added to the injected

water to prevent the corrosion possibility.

2.2.3.4 Air/Gas fluid operations

Air or gas was the first fluid used for underbalanced operations. Air, nitrogen, or natural gas

(preferably methane) is used in UBD. Underbalanced drilling operation with air injection is

common while there is always possibility of significant corrosion and downhole fires. To avoid

these problems nitrogen has become the gas of choice for UBO.

Advantages to Air/Gas fluid operations: Air/gas fluid operations have advantages similar to

several other UBO [Medley G.H.et al., 1998 and R.A. Joseph, 1995]. Advantages are

i. Increase ROP

ii. Increased bit life

iii. Minimal formation damage.

iv. No hidden productive zones

v. Early production

vi. Better production from openhole completions

vii. Reduction of lost circulation and elimination of pipe sticking possibility.

Air/gas fluid operations has three main limitations which are water inflows, wellbore instability,

and downhole fires. The flow of water from the formation to within the wellbore during

operation is termed as the water influx. Water invasion causes the cuttings to ball up the bit and

form mud rings on the wall of the hole (Fig.2.24). These decrease the life of bit and mud rings

limit hole cleaning. For water influx shutoff specific size material is injected into the water-

producing formation, where it sets to form a barrier to water flow. Other fluid system may be

used to overcome this problem.

40

Fig. 2.24 Shales destabilized by water invasion due to formation of mud rings, which clog the

hole, after [Rehm B., 2002].

The possibility of downhole fires is a potential limitation on the use of dry air operation due to

various factors like improper cooling of the downhole system and formation of mud rings above

the drill collar. The presence of liquid hydrocarbons increases the chances of down hole fires. As

soon as the mixture of liquid hydrocarbon and dry air reach its ignition temperature the

downhole fires start. Three stages of development of downhole fires is explained below

(Fig.2.25):

a. The top of drill collars where the cuttings accumulate due to low velocity region in the

annulus.

b. Mud ring formation in presence of liquid influx as the cuttings pack off around the

drillstring in regions of low velocity.

c. During Air circulation if liquid hydrocarbon comes out through influx, there is an isolated

chamber is generated below the pack off region which leads the fire ignition.

41

Fig.2.25 Mud ring formation and downhole fire, after [Medley G.H.et al., 1998].

Wellbore Instability is the serious concern during this fluid system. This air or gas fluid system

provides the lowest wellbore pressures of any other method. These low wellbore pressures can

cause collapsing of wellbore especially in weak formations. Water influx also creates the well

bore stability problem.

The oxygen level in water is a major factor in corrosion during air/gas fluid operations.

Increasing hydrostatic pressure in the fluid causes additional oxygen to be dissolved from a gas

source, which makes more corrosive environment. In distilled water at ambient temperature and

pressure, the critical concentration of oxygen is 12 ppm. This would be the oxygen level in water

that would cause the most corrosion [Ghalambor A. et al., 2004]. The dissolved oxygen in water

trend can be seen in Fig. 2.26. Nitrogen can be used in place of oxygen to reduce the corrosion.

42

Fig. 2.26 Oxygen partial pressure in distilled water [Medley G.H.et al., 1998].

Specific volume of gas is required for the successful operation. Angel’s method presents an

equation to determine the volume or circulation rate at particular depth with a specific hole size.

The figures in Angel's tables are about 30% low for deep wells but are adequate for shallow

wells. Fig.2.27 is a graph that plots circulation rate versus hole depth. As an example, Angel's

graph shows that in a 15,000-ft hole that is 8¾ in. in diameter, drilling at 60 ft/hr, the circulation

rate should be about 2,000 ft3/min.

43

Fig.2.27 Angel’s Curves for air drilling, from [Medley G.H.et al., 1998].

2.3 Candidate Screening and Selection

2.3.1 Drivers to consideration of underbalanced operations

The process of UBO candidate screening begins with the answer to the question, “What are the

reasons for considering UBO in this well or field?” The reason the question is framed in this way

at present is that UBO has often been implemented in order to overcome problems or obstacles

associated with conventional operations. It means that the primary choice is conventional

techniques and UBO is only considered if conventional operations are either facing many

problems or impossible.

44

In general, at the current state of the technology, the key drivers for the selection of UBO have

been:

i. Severe lost circulation or differential sticking problems

ii. Highly depleted reservoirs, which typically present the various problems

iii. Hard rock formations that result in very low rates of penetration and poor bit life during

conventional operations.

iv. Formation damage resulting in wells with productivity much below it’s potential.

v. Early production

2.3.2 Reservoir aspects of underbalanced operations

Feasibility study is necessary before undergoing any underbalanced operations. A proper study is

mandatory about the reservoir for a successful operation. Damage mechanism in the reservoir

must be studied which will not only ensure that we should go for underbalanced operations but

also gives the idea which method is suitable for the reservoir and the other benefits. Few

reservoirs are good candidates for underbalanced operations and result in an enhanced recovery.

Other formations or fields may not be suited to underbalanced operations for a variety of other

reasons. A summary of indicators that help to determine whether a particular reservoir will be a

good or bad candidate for UBO is pointed below.

2.3.2.1 Good candidate indicators for UB operations

• Hard rock formations are usually consolidated and good for underbalanced operations

because of well stability as well as good candidates because of the higher ROP and bit

life from underbalanced operations.

• Mature field or depleted reservoirs exhibit lost circulation and differential sticking

problems. If formation is consolidated, makes an excellent candidate for UBO.

• Naturally fractured and vugular formations usually exhibit huge losses, which can

exacerbate well control problems or lead to differential or mechanical sticking, making

them good candidates for underbalanced operations.

• Highly permeable formations with less pore pressure are also good candidates for UBO.

45

• Formation that usually suffer major formation damage by the invasion of fluids during

drilling or completion operations. Wells with a skin factor of 5 or higher is a good

candidate.

• High production reservoirs with low-medium permeability.

• Formations with rock-fluid or fluid-fluid sensitivities.

Underbalanced operations are not a technology that should be utilized for all situations. Utilizing

the technology in the wrong application may create an unsafe situation, increase formation

damage, increase the probability of well failure or increase well cost without any probability of

economic gain.

2.3.2.2 Bad candidate indicators for UB operations

• Formations where knowledge of reservoir pressure is poor.

• Poor quality reservoirs. If there is nothing in reservoir UBO will not do any thing.

• Swelling shale and unconsolidated formation. Wellbore stability problems during

underbalanced operations underbalanced.

• High pore pressure coupled with highly permeable formations will require costly

equipment and extra accessories for UBO.

• Formation susceptible to spontaneous imbibitions.

• Wells which require frequent trips could create excessive oscillation between

underbalanced and overbalanced conditions, causing damage, and eliminating the

advantages of UBO.

• Candidates requiring UBO for long intervals..

• Wells with high H2S. High levels of H2S will complicate the system design and

associated risk with safety.

• Hole sections with variations of pressure. Sometimes it may be feasible to reduce the

wellbore sufficiently so that all zones produce into the well.

46

The IADC underbalanced operations committee worked to promote the safe and efficient

application of underbalanced operations worldwide. The following standard classification

system for UBO and a set of standard nomenclature is given by the committee, which are

listed in Tables 2:

Table 2 -IADC UBO Committee classification system for UBD wells

.

Level Description

0 Performance enhancement only; no hydrocarbon containing zones.

1 Well incapable of natural flow to surface, inherently stable and a low-level

risk from a well point of view

2 Well capable of natural flow to surface but enabling conventional well

control methods and has limited consequences in the case of catastrophic

equipment failure.

3 Geothermal and non-hydrocarbon production. Maximum shut in pressures are

less than UBD equipment operating pressure rating. Catastrophic failure has

immediate serious consequences.

4 Hydrocarbon production. Maximum shut-in pressures are less than UBD

equipment operating pressure rating. Catastrophic failure has serious

consequences.

5 Maximum projected surface pressure exceeds UBO operating pressure rating

but are below BOP stack rating. Catastrophic failure has immediate serious

consequences

2.3.3 Assessing rock potential for formation damage

Formation damage assessment is necessary before selecting a candidate for underbalanced

operation. Formation damage may be through the various reasons. Various damage mechanisms

are explained below. If possibility of formation damage is making significant reduction in

47

permeability and ultimately reducing the expected production with the conventional techniques

then we will go for the UB operation.

Formation damage with fines migration occurs due to the loosely bonded matters within the rock

matrix. This may be induced due to the filtrate invasion near the well bore region. Filtrate

invades into the formation by the high hydrostatic pressure of the fluid column where it makes

loosely bond or preexisting particulate matters to move. The particles then become a barrier in

the natural permeability of the rock. Depth of formation damage depends of the exceeding

hydrostatic pressure. It may be vary from few inches to feet of radius around the well bore.

Migrating fines can be a any type of formation materials depend upon the mineralogy of the

formation which includes clays (a typical size less than 4 µm) and silts (sizes ranging from 4 to

64 µm). Table 3 presents particle mineralogy and its constituents.

Table 3.Main components of various clay and fine particles, from [Economides M. J.et al., 2000]

Particle Mineralogy Major Components

Quartz Si, O

Kaolinite Al., Si, O, H

Chlorite Mg, Fe, Al., Si, O,H

Illite K, Al., Si, O, H

Smectite (montmorillonite) Na, Mg, Ca, Al., Si, O, H

The damage with fines migration can be minimized. When the wetting phase of the reservoir is

in motion at that time fines migration tends to be most significant. Velocity of the fluids flowing

in the pore space, pore-size distribution and size of fines control the severity of problems. In high

underbalanced case the high rate early production initiates the fines mobilization. This

mobilization can be from early drilling stage to the production phase of oil well operations.

The formation damage may be due to the reactive clays in the sandstone formations. Certain

clays like smectite are susceptible to hydration by fresh-or low-salinity water contact.

Deflocculation or dispersion in kaolinite caused by abrupt salinity transitions or caustic pH

48

[Vitthal S. et al., 1989]. Several authors [Economides M. J. et al., 2000; Azari M. et al., 1988 and

Sharma M.M. et al., 1985] have dealt with clay swelling in sandstones, showing factors that

cause clay dispersion. Smectite and smectite mixtures are most common swelling clays. Swelling

can increase its volume up to 600%, significantly reducing permeability. Smectite occupies the

larger pores and especially the pore throats.

The formation damage may be due to clay deflocculation. Clay deflocculation is caused by a

disruption of the electrostatic forces holding the surfaces of individual clay units that are

attracted to each other as well as the walls of the pore system. A rapid salinity change from high

to low ion concentration, or rapid transitions in pH can create deflocculation. By using

underbalanced operation the above problems can be eliminated/minimized as there is very less

chances of filtrate invasion in the formation.

The permeability impairment caused by clays has been worked out by researchers. It has been

widely known that a variety of clays are sensitive to changes in the fluid pH and to the

concentration of certain ions. To determine the potential permeability impairment caused by clay

swelling and fines migration, the author [Vitthal S. et al., 1989] established two damage indices,

which is particularly used to estimate the potential reduction to rock permeability as a result of

clay swelling (swelling index) and fines migration (fine-migration index). To calculate the

overall damage potential of the rock, each clay index is multiplied by its corresponding weight

coefficient and its volume fraction. The overall damage potential is the sum of these products.

The overall swelling index is calculated as below:

Eq. 2.5

The swelling potential (in percent) is given by

Eq. 2.6

The overall fines-migration index is given by

Eq. 2.7

49

Here Vi is the volume fraction of the particular clay. The fines-migration potential (in percent) is

given by

Eq.2.8

The percentage values of indices are equivalent to probability values for the occurrence of fines

migration and clay swelling events. Tables 3 show the swelling index and fine migration index

for clay components and Table 4 provides a summary of the damage indices for various clay

types and their distribution correction factors, respectively.

Table 4. Damage indices for pure clays [Vitthal S. et al., 1989]

Table 5 - Distribution correction factors [Vitthal S. et al., 1989]

Phase trapping refers to the permanent increase in trapped fluid saturation in a porous space of

rock matrix. The losses of mud filtrate to the formation in the near-wellbore region caused by

50

leak off during conventional overbalanced operations. This can result in permanent entrapment

of a portion or all of the invading fluid. The blockage of the invaded fluid causes a reduction in

the relative permeability to oil or gas near the wellbore boundary.

Fig. 2.28 Relative permeability curves illustrating water block caused by extraneous water

introduced drilling, coring, or workover fluids [Economides M. J. et al., 2000].

In figure 2.28, increasing the water saturation from 20% to 35% decreases the relative oil

permeability from 90% to 30%, respectively.

Phase trapping may occur due to invasion of water-based fluids/filtrates into regions of low

water saturation, invasion of oil-based fluids/filtrates into zones of low or zero oil saturation.

Phase trapping is caused by production condensate type gases below the dew point pressure

which results in the accumulation of condensate type gases near-wellbore region. Another

Water saturation (% Pore space)

R

elat

ive

P

erm

eabi

lity

51

condition of phase trapping is the production of liquid hydrocarbons below the bubble point

resulting in the release of gas from solution and the formation of trapped critical-gas saturation.

The formation damage caused by bacteria is termed as bacterial damage. This type of damage is

associated with the introduction of viable bacteria to the formation. Bacteria grow in the

formation either in aerobic or anaerobic environment. During any water added operation in the

well leads to the bacterial damage problem. The problem occurs in certain bacteria favorable

environment. Bacteria can grow in many different environments and conditions: temperatures

ranging from 12°F to greater than 250°F, pH values ranging from 1 to 11, salinities to 30% and

pressures to 25,000 psi [Economides M. J. et al., 2000]. Damage mechanism attached with

bacterial damage are like plugging of pore spaces, some sulfate reducing bacteria creates toxic

environment, some bacteria creates corrosive environment which leads to the failure of down

hole equipments. The other formation damage are formation fluid/extraneous fluid

incompatibility and rock/fluid incompatibility.

The proper use of underbalanced technology prevents the continuing losses of potential water-

based fluids which may contain viable bacteria colonies into the formation. Therefore during the

water based fluid operations bacterial treatment is necessary. Generally it is treated by oxidants,

or by biocides. Table 6 presents a summary of the formation type vs. damage mechanism which

has been given by [Bennion D.B., 2002]. This matrix of formation damage mechanisms provides

the damage mechanism possibility & probability with formation type under various conditions.

The matrix will help to predict the possible formation damage for a particular well. The

candidate then is selected either it should be operated underbalanced or not.

52

Table 6 - Damage mechanism vs. formation type matrix, after [Bennion D.B., 2002]

53

2.3.4 Assessment of lost circulation potential

The phenomenon of losing drilling, completion fluids partially or in totality in to the formation

are termed as lost circulation. These losses can occur in naturally fractured formations,

unconsolidated and highly permeable formations. The losses are due to high hydrostatic pressure

of mud column exceeding the formation pore pressure and the losses are through the large pore

openings of naturally fractured or in induced fracture regions. To determine the lost circulation

potential is determined by the following procedure.

i. Estimate of both permeability (k) and porosity (ɸ).

ii. A qualitative description of the reservoir. The presence of natural or induced fractures

and the presence of vugs.

iii. The presence of fractures is assigned an index (IFr) that takes the value of 10 for highly

fractured formations, and the value of one for un-fractured formations.

iv. The presence of vugs is assigned an index (IV) that takes the value of 10 for vuggy rocks,

and the value of one for rocks that do not display any vugs.

v. A number between 1 and 10 for both indices may be selected based on experience.

vi. Lost circulation index (ILC) is the product of all the above variable factors as being the

independent events.

The lost circulation index can be formulated as follow:

Eq.2.9

Lost circulation index calculated from the above formula can be compared from the below

relations to know the lost circulation potential.

ILC ≥ 5% Severe lost circulation problem

ILC < 0.1% No lost circulation

ILC 5% ≥ ILC ≥ 0.1% Some losses

54

2.3.5 Assessing pipe sticking possibility

Pipe sticking possibility assessment is important during the candidate selection. During the

conventional operation, the problem of sticking pipe increases the non productive time.

Sometimes problem is severe upto such extent that the organization lose it’s all down hole

assemblies below the stuck up region. Pipe sticking occurs because of the filter cake formation

build up at wall. The differential pressure between the fluid column and the formation leads to

sticking of pipe. Once the pipe stuck the pressure differential acts as the force which holds the

pipe against the wall of well bore. The holding force is determined by multiplying the differential

pressure by the cross sectional area of the pipe imbedded in the wall cake.

The stuck pipe problems are studied and analyzed by [Sharif Q., 1997]. The author analyzed

from the history and data of various offshore located well and prepare a model to predict the

probability of getting differentially stuck. The model can be used for determining the pipe

sticking possibility for a selected candidate. The probability function developed by [Sharif Q.,

1997] is given by:

SDSI = - 4.4 + 0.5 × CC + 0.075 × SOL × EMW + 0.0045 × DIA × ROP Eq. 2.10

Eq. 2.11

Where SDSI is “Sharif’s” Differential sticking index.

.

UB operations eliminate both the filter cake and the differential pressure. As most multiphase

fluids do not have solids that produce the filter cake, one will not be generated. In underbalanced

operations differential pressure acts from the reservoir to the annulus. If designed properly, it is

impossible to have positive differential pressure in underbalanced operations.

55

2.4 Well Control Aspects in Underbalanced Operations

Well control in underbalanced operations is very critical because the formation fluids are

allowed in to the wellbore during drilling and flow to the surface under controlled conditions.

ERCB (Energy Resources Conservation Board), Calgary, Canada has laid down guidelines for

executive underbalanced operations safely. Well control involves the surface BOP system and

subsurface system.

2.4.1 Blowout prevention system

BOP stack shall consist of diverter preventer, annular preventer, diverter line, kill line, pipe ram,

blind ram, emergency bleed off, for a convention rotary rig . BOP stack for coiled tubing drilling.

The accumulator system used to control the diverter preventer shall be independent of the rig’s

standard accumulator system. No primary well control equipment (blowout preventer other than

the diverter preventer) shall be used for stripping, snubbing or drilling except in emergency

situations. The diverter preventer may be a rotating blowout preventer or a rotating head.

Rotating head is a low pressure diverter designed for rotation with drill pipe or kelly stem.

Rotating head provide a rotating seal that allows drilling to proceed under pressure. In the past

rotating head was typically limited to just few 100 psi (upto 500 psi).Rotating blow out

preventer is an annular preventer designed to rotate with pipe rotation and capable of providing a

seal on both smooth pipe or kelly stem. The rotating blowout preventer (RBOP) is used to

maintain surface pressure upto 1500 psi.

2.4.2 Sub-surface control system

At least two non ported devices (floats) should be installed near the bottom of the drill string to

prevent back flow from the well during underbalanced drilling. One of these devices can be a

profile nipple designed to accommodate a pump down back- flow device. When planning to use

air fluid system for underbalanced operations, precaution shall be taken to ensure explosive

mixtures are not generated at any point of operation. Fire floats/ fir stops are used near the

bottom of the drill pipe to shut off air flow automatically if a down hole fire is initiated.

56

2.4.3 Well control equipment

Jointed pipe systems: The conventional BOP stacked used for drilling is not compromised during

underbalanced drilling operations. The conventional BOP stack is not used for routine operations

and will not be used to control the well except in case of emergency. A rotating control head

system and primary flow line with ESD valves is installed on top of the conventional BOP. If

required a single blind ram, operated by a special koomey unit is installed under the BOP stack

to allow the drilling BHA to be run under pressure.

Fig. 2.29 Jointed pipe system for well control (Courtesy: Zueitina Oil Company, Libya)

57

Coiled tubing system: Well control when drilling with reeled systems is much simpler. A

lubricator can be used to stage in the main components of the BHA or if a suitable downhole

safety valve can be used then a surface lubricator is not required and the injector head can be

placed directly on top of the wellhead system. Reeled systems can be tripped much faster and the

rig up is much simpler. One consideration that must be made with reeled systems is the cutting

strength of the shear rams. It must be verified that the shear rams will cut the tubing and any

wireline or control line systems inside the coil. For a stand-alone operation on a completed well

an example stack up is shown in figure 2.30.

Fig.2.30 Coiled tubing system for well control (Courtesy: Zueitina Oil Company, Libya)

58

2.5 Problem Identified

• A stable low gravity fluid formulation is desirable, as foam stability is major concern

during the underbalanced operation. Gasified fluid operation does not maintain the

continuous underbalanced condition thus requires the injection of compressed gases

through annulus which is not effective at higher depths and typically deviated wells.

• Due to poor hole cleaning in horizontal well, underbalanced condition is lost which leads

to the unwanted formation damage.

• In horizontal wells the fluid invasion will be through the gravity when underbalanced

condition is lost.

59

Chapter 3: Methodology & Experimental work

The methodology adopted for absolving the problems identified during literature survey is as

follows:

i. To study and identify the feasible low gravity solids which can reduce the density of fluid

column during underbalanced operation and can provide a stable low specific gravity

fluid formulation for sub-hydrostatic underbalanced workover operation.

ii. To study the Non invasive mechanisms and to develop the non invasive fluid formulation

for sub-hydrostatic underbalanced workover operation.

3.1 Development and Evaluation of Low gravity, Non invasive Water based Fluids for

sub-hydrostatic Underbalanced Workover Operations

Before involving in the development of Non invasive, low gravity workover fluids for sub-

hydrostatic / depleted reservoirs, it is very important to undergo about the entire geological

aspects of the specific field as well as fluid components selection with couple of factors

capability and economic feasibility. The followings are very brief introduction about the fluid

components which are used in laboratory experiments for development of low gravity and Non

invasive desired fluids.

Organic polymers

During the formulation of drilling, completion and workover fluids the organic polymer plays

very vital role. They are used in fluids to reduce filtration, stabilize clays, flocculate drilled solids

and increase carrying capacity. They also serve as emulsifiers and lubricants. They are composed

of a number of repeating or similar units. The groups of atoms, called monomers are consisting

primarily of compounds of carbon. The term organic polymer is applied to the several varied and

60

versatile substances which are composed of a number of repeating or similar units, or groups of

atoms (called monomers) consisting primarily of compounds of carbon. Organic colloidal

materials are used in drilling fluids to reduce filtration, stabilize clays, flocculate drilled solids,

increase carrying capacity, and (incidentally) to serve as emulsifiers and lubricants. They have

versatile characteristics so it is used for multipurpose requirements. Polymers like starch and

guar gum is naturally available. Other semi-synthetic polymers like sodium

carboxymethylcellulose are also used as a component of fluid. The derivative of starch and

gums are also used as organic polymer. These are used after few processing. Polyacrylates and

ethylene oxide polymers are purely synthetic. They are the derivatives of petrochemicals. The

organic polymers develop highly swollen gels even in very low concentrations.

XC polymer

Xanthan gum production method was developed at the Northern Regional Research Center,

Agricultural Research Service, U.S. Department of Agriculture, Peoria, Illinois, in 1961.

Xanthan is a water-soluble polysaccharide produced by bacterial action (genus Xanthomonas) on

carbohydrates. It was introduced as a drilling fluids component in the mid 1960s under the name

"XC polymer," The polymer builds viscosity in water or salt solutions. Xanthan gum solutions

show exceptional shear-thinning property. Cross-linking of XC polymer with chromic ion

increases viscosity. The increase in pH has very little effect on it’s viscosity. XC polymer does

not show degradation upto 1200C. It is used in the fluids as a thickener or a suspending

agent. It has exceptional suspending ability at low concentrations. Xanthan gum is not a

filtration-control agent. Xanthan gum is used in very low concentrations of 0.2 to 2 lb/bbl (0.6-6

kg/m3) [H.C.H. Darley and G.R. Gray, 1988].

Sodium carboxymethylcellulose

It is generally abbreviated as CMC. Cellulose comprises the greater part of the cell walls of

plants. Sodium carboxymethylcellulose is a water-dispersible, colorless, odorless, nontoxic

powder. It is preferred to starch for applications in other than high-pH and salt-saturated muds.

CMC costs more than starch but quantity needed to reduce filtration rate is less compared to

starch.

61

Polyanionic cellulosic polymer

It is generally abbreviated as PAC. PAC thickens salt solutions. When PAC is used with

diammonium phosphate, it provides an environmentally acceptable polymer-electrolyte, shale-

inhibitive composition. The polymer solution alone has exceptional inhibitive qualities. The

concentration range of PAC is from 0.2 to 5 lb/bbl (0.6 to 14 kg/m3 [H.C.H. Darley and G.R.

Gray, 1988].

Hydroxy ethyl cellulose

It is generally abbreviated as HEC. HEC is nonionic. HEC is effective in reducing filtration and

in thickening salt solutions. Although HEC can be used in drilling muds, more commonly it is

used in completion fluids. HEC is used in concentrations of 0.2 to 2 lb/bbl (0.6 to 6 kg/m3).

Inorganic Chemicals

Magnesium oxide (MgO)

It’s common name is magnesia. It found as white powder, very slightly soluble in water. MgO is

produced by calcining the hydroxide, carbonate, or chloride. It is used as a buffer, or stabilizer,

in acid-soluble completion fluids in conjunction with polymers. It is generally used in a

concentration of 0.5 to 2 lb/bbl (1to 6 kg/m3) [H.C.H. Darley and G.R. Gray, 1988]. .

Potassium chloride (KCl)

It’s common name is potash. It appears colorless or white crystals. It is mined and then; purified

by re-crystallization. It is generally used in a concentration 2 to 60 lb/bbl (6 to 170 kg/m3).

Potassium hydroxide (KOH)

It is generally called as caustic potash. It can be found as white lumps, pellets or flakes. It is

prepared by electrolysis of potassium chloride. It is toxic by ingestion and inhalation. It used to

increase pH of potassium-treated muds and to solubilize lignite. It is generally used in

concentration 0.5 to 3 lb/bbl (1 to 8 kg/m3).

Sodium chloride (NaCl)

It appears as white crystals. It is produced by evaporation of brines and by dry mining. It is used

to prepare brine in completion and workover operations to saturate water before drilling rock

62

salt. It is used to lower freezing point of mud, raise the density (as a suspended solid) and act as a

bridging agent in saturated solutions. It is generally used in Concentration 10 to 25 lb/bbl (30 to

360 kg/m3).

Sodium hydroxide (NaOH)

It is generally called caustic soda. It is found in shape of beads, pellets, flakes. It is produced by

electrolysis of sodium chloride. It is used in water muds to raise pH, to solubilize lignite,

lignosulfonate and tannin substances. It is also used to counteract corrosion, and to neutralize

hydrogen sulfide. It is generally used in concentration 0.2 to 4 lb/bbl (0.6 to 11kg/m3).

Surfactants

The term surfactant is basically the phrase surface-active agent. It is the substance which acts at

an interface between two phases. Surfactants are used for several purposes. They serve as

emulsifiers, foamers, defoamers, wetting agents, detergents, lubricants, and corrosion inhibitors.

Hollow glass spheres (HGS)

The hollow glass spheres are unicellular, made from soda lime borosilicate glass, chemically

inert other than in the presence of HF, and having high water resistance along with high

temperature and pressure resistance. The concept of adding HGS is to decrease the density of the

base fluid and create a light weight yet incompressible fluid was seen as a potential solution to

the design of workover fluids for sub-hydrostatic wells. HGS are engineered fillers and have

been used in many industries aerospace and automotive, where weight reduction while

maintaining strength is beneficial. Also because of their high strength to weight ratio, HGS find

utilization in buoyancy modules for subsea risers.

Precedent existed for the use of spheres [Medley, George H. et al., 1995], although not hollow

glass as well as near sphere shaped particles have already been used drilling and cementing

application as well. Under relatively challenging conditions of temperature and hydrostatic

pressure demands, an inert additive with high tolerance for iso-static pressure environment is

desirable .The HGS selected for evaluation had a good combination of physical properties. There

are many attractive features of HGS none as dominant as the simplicity of the approach. HGS

63

can be added to virtually any type of existing fluid system in order to reduce its density. HGS

basically extends the density window of a single phase liquid into a density range which is

normally only achievable by the injection of a gas to liquid.

Density of HGS based workover fluids

Addition of HGS to any fluid reduces its density. The density reduction is proportional to the

concentration of HGS in the fluid, so increasing HGS concentration decreases the fluid weight.

There are practical limitations as to how much weight reduction can be accomplished for a given

HGS grade. The upper limits of HGS addition are controlled by viscosity and will vary

somewhat for different bases [Medley, George H. et al., 1995].

Field handling of HGS

HGS material properties dictate their handling. Understanding handling principles for materials

with diameter less than 100 microns and with low bulk density is important in implementing

successful field usage. HGS are slightly more challenging than free flowing coarse granules or

pellets. Their sizes, shape, density, and pore size distribution can create a nuisance dusty

environment if improperly handled, especially indoors at a fluid plant. At a rig site, they can be

unloaded from their boxes or bags either manually, by gravity feeding into a compounding

hopper or mechanically or by using pneumatic conveying system. The unloading personal should

wear safety goggles before unloading by either method [Medley, George H. et al., 1997].

HGS Suspension

The density ratio of hollow glass spheres of SG=0.38 to water is approximately the inverse of the

density ratio between low density solids, representative of formation cuttings and water .Based

on the similarity of these ratios, it would be expected that the segregation velocity for both type

of particles would be the case for hollow glass spheres which being less dense than water would

float. As a result it is expected that a properly formulated underbalanced workover fluid,

designed to suspend and transport, would also do fairly well suspending HGS. In fact

experimental observations have confirmed that hollow glass spheres are maintained in

suspension for extended time periods in fluids, especially when fluids are non-Newtonian. For a

64

non-Newtonian fluid, the settling speed is thought to be linked more with rheology rather than

density differential between the particle and the medium.

Formation damage tests (Permeability Return) The result of formation damage tests have been reported by the author with Berea cores using the

formation testing apparatus. These tests showed that HGS help from a tight filter cake and

caused less formation damage than the corresponding fluids without HGS. The filter cake can be

removed by back flooding and the original permeability was completely restored [Arco M. J. et

al., 2000].

Lubricity and Casing Wear

Solid plastic spheres are routinely used as friction reducers in highly deviated wells. Medley

tested the potential reduction of friction and casing wear in conventional water-based fluids

which contained HGS.A significant reduction in drill string and casing wear was noted.

Non Invasive Fluids: It’s a new class of ultra low solids drilling fluids which are technically

advanced and are the successor to the low solids non dispersed fluids .These are capable of

replacing the use of oil. These consist of an optimum blend of soluble synthetic polymers and

partially soluble and insoluble non ionic polymers with varying hydrophobic liophilic balance

(HLB) ratio. During overbalanced conditions in the well bore, they form an impermeable film on

the wall of well bore and therefore do not allow the fluid to invade the formation beyond few

inches. It greatly helps in stabilizing the well bore .In the pay zone , when pressure is removed

and well is flowed , the film is removed thereby permeability is restored.

Mechanism of invasion and its control: Two invasion mechanisms are relevant. Static filtration

occurs when fluid pumping is interrupted and filtration occurs due to the hydrostatic pressure in

the well and reservoir pressure .Under static conditions, the cake thickness increases as a

function of time and the filtrate volume proportionally increases with the square root of time.

The filtration rates are controlled by the continuously increasing the thickness of filter cake in

conventional overbalanced operations. Dynamic or cross filtration occurs when the fluid is

65

pumped through well. In this process the cake thickness results from the dynamic equilibrium

between the solid particles deposition rate and erosion rate due the shear stresses generated by

the fluid flow through the wellbore. Under dynamic filtration, the cake thickness and

permeability are constant with the time and the filtrate volume proportionally increases with

time.

Two mechanisms of invasion control is identified for minimizing/eliminating the invasion

possibility. One through the plugging solids that promote the external and internal cake

formation and other through the liquid phase resistance to flow in the porous medium.

Factors governing invasion:

i. Rock permeability and porosity

ii. Wellbore –reservoir pressure differentials

iii. Native fluids properties

iv. Nature of fluid flowing through porous medium

v. The adsorption level of polymers used. There are different parameters responsible for it

like polymer structure, charges, molecular weight etc. The adsorption value of starch only

gives global information since this polymer may not be completely soluble. The

adsorption levels are ranked as: starch > xanthan ≥ PAC etc.

vi. Temperature and pressure affects behavior and interactions of water or oil, clay, polymers

and solids in mud. The effect of increasing the temperature of a liquid is to reduce the

cohesive forces while simultaneously increasing the rate of molecular interchange. The

former causes a decrease of shear stress while the latter causes it to increase. The net

result is that liquids show a reduction in viscosity with increasing temperature. The effect

of increased pressure on oil based mud is to increase the cohesive forces, which leads to

increase the viscosity.

vii. Extensional viscosity

viii. Trouton ratio: It is (a relation between extensional and shear viscosity at similar

shear/extensional rates) the major rheological parameter governing fluid invasion

mechanism.

66

Methodology for the Formulation of Non Invasive Fluids

The solids free non invasive fluid consists on identifying polymeric solutions that generate

extremely high pressure drop when flowing through porous media without showing excessive

viscosity in the well. Thus without limiting the pumping capacity of the system its rheological

behavior prevents the invasion into the rock.

FLC 2000

FLC 2000 is the main additive in the fluid formulated to control the invasion of fluid into the

formation. Extensive testing using a range of different mud weights in a water base mud system

shows that FLC 2000 is capable of working effectively in everything from a low density solids

free fluid to 16 ppg mud. It is unaffected by contamination, in fact here is often a small

improvement in the low invasion properties when OCMA clay is added.

By using magnesium oxide as a pH buffer in the water based mud formulations, the excellent

sealing properties of FLC 2000 are better preserved after hot rolling at (2500F & 300 psi for 18

hours). Then if potassium hydroxide or sodium hydroxide is used, it appears that combination of

FLC 2000 and MgO also helps in stabilizing the other polymeric additives such as XC Polymer

during heat aging. MgO alone without FLC 2000 is not effective. The most common way to

reduce invasion is to load the fluid with sized calcium carbonate because of the lack of solids in a

brine system as it has always been very difficult to prevent formation invasion with this brine

system. FLC 2000 (unique blend of polymers and sized, surface modified particles) easily

transforms a range of brine systems into a very good ULIF (Ultra low invasion fluid) without

bridging agents such as calcium carbonate. Even with the high concentration of calcium ions

present, FLC 2000 performs very well. It is suitable for use in oil based mud and synthetic based

fluids as well as water based mud. Both oil and synthetic based fluids are generally considered to

be a low invasion fluid, but when compares to the fluid system with FLC 2000, it is apparent that

this product will lower invasion even further by adding as little as 2ppb FLC 2000 to some

fluids.

67

FLC 2000 and its role

FLC 2000 additive is a blend of soluble synthetic polymer, and partially soluble & insoluble non-

ionic polymers with varying hydrophobic liophilic balance (HLB) ratios. It is a synergistic blend

of modified low molecular weight polymers, surface functionalized organic solids and other

additives.

Properties of FLC 2000

i. Appearance : Dry tan colored, free flowing powder,50-500 mesh size

ii. Specific Gravity: <1

iii. Bulk Density: 30-40 lb/cu ft

iv. Broad particle size distribution for optimum sealing of wide range of pore and fracture

openings.

v. Biodegradable

vi. pH: Near neutral at 3% concentration in water.

Functions of FLC 2000

FLC 2000 is responsible for providing non invasive property in non invasive fluid system. It is

used in drilling, workover and completion fluids to form ultra low invasion fluid. The products

forms a compressible, extremely low permeability filter cake which minimizes fluid invasion and

the transmission of bore hole pressure to the formation despite high pressure differential (200 psi

or more) for a considerable time. The very low permeability barrier formed by the FLC 2000

additive is much more effective at preventing fluid invasion than conventional fluid additives

and as such greatly reducing formation damage, reducing the risk of differential sticking and

prevents wellbore instability. The barrier also effectively increases the fracture gradient and so

widened the safe drilling window by allowing the wellbore fluid density to be raised without

inducing losses.

The results of various experiments performed by using non invasive fluids additive FLC 2000 as

an effective non-invasive composition in the sand bed of very high permeability and are highly

68

encouraging. This shows that the impermeable film formed by non invasive fluid additive has a

high strength to withstand the pressure rigors of borehole.

Wellbore strengthening

Wellbore stability is the prime consideration in underbalanced operations, for avoiding

unpredictable borehole problems and to reduce non productive time during drilling. FLC 2000

form an ultra low permeability barrier very quickly across matrix permeability or micro-fracture

openings. This can restrict pressure and fluid invasion enough to give an appreciable measure of

wellbore strengthening. The effectiveness of FLC 2000 in giving wellbore strengthening in

permeable formations is undoubtedly due to the very low permeability of the filter cake formed.

It is too soft a material and is present in too low a concentration to work by stress cage

mechanism. While it is feasible that the product can form a very low permeability seal that is

completely enough (and formed quickly enough) to prevent the initial pressure penetration into a

permeable formation (and hence stop a fracture initiating), it is more likely that the additive

mainly functions by plugging a fracture with a very low permeability membrane once it starts to

grow – the formation of this seal will stop the invasion of wellbore fluids in to the formation.

Advantages with FLC 2000:

i. It can be applied in any water-based, oil-based and synthetic-based drilling completion

and workover fluid.

ii. The blend is designed for ease of mixing in all systems with minimal increase in

viscosity.

iii. The low permeability cake is easily removed by flow back or by simple wash fluids.

iv. It provides invasion control that exceeds that seen with sized solids and other

conventional systems.

v. Imparts wellbore stability to micro-fractured/ bedded shales and brittle coal seams.

vi. Reduces formation damage and differential sticking.

vii. Increases the fracture gradient to reduce induced losses during drilling, completion and

workover operations.

69

Working principle of FLC 2000 FLC 2000 is a blend of modified cellulosic polymers and surface functionalized organic solids.

The molecular weights of the polymer components are low, which allows easy mixing and does

not significantly contribute to fluid viscosity. The high grade polymers and organic solids in FLC

2000 are modified to exhibit a range of water and oil solubility as well as wettability. When FLC

2000 is added to a water based fluid certain components partially miscible because of their oil-

loving characteristics. These components assemble into small deformable aggregates that give an

FLC 2000 fluid its ultra low invasion and non-damaging characteristics. The similar mechanism

operates in oil based fluids except that here it is the more water loving components now produce

the aggregates. The aggregates are present in the fluid in a very wide range of sizes (from a few

microns to several hundred microns in diameter) provides the excellent invasion control. As well

bore fluid tries to enter rock pores or micro-fractures because of the overbalance pressure; an

ultra low permeability layer of aggregates quickly forms and greatly reduces any further invasion

of solids or fluid. The aggregate making up the layer are deformable so as the pressure is raised,

they are increasingly compressed and the barrier even further. FLC 2000 makes a virtual caging

called stress caging and provides strength to formation. It also works as sealant, thus prevent

fluids as well as pressure transmission into the formation.

Micronized calcium carbonate (MCC)

Calcium carbonate is recommended as a weighing material because the filter cake that form on

the productive formation can be removed by the treatment of hydrochloric acid. Calcium

carbonate is readily available as ground limestone or oyster shell. Calcium carbonate is dispersed

in oil muds more readily due to its low specific gravity (2.6-2.8) .The maximum density of the

mud is about 12 lbs/gal (1.4 gm/cc). High filtration slurries carrying graded marble or limestone

particles in suspension have been found effective in overcoming loss of circulation.

Micronized calcium carbonate abbreviated as MCC is one of the most important components of

non damaging fluid systems, which acts as bridging material. Bridging is required at the pore

throat of the reservoir and to initiate filter cake formation. The filter cake itself will then control

70

further losses of filtrate to the formation and migration of fines. Calcium carbonate has been used

as one of the main bridging agent s as it is readily available in desirable particle size distribution.

By designing the ideal particle size distribution of MCC (i.e. bridging material) in fluid system,

for a given pore size distribution in the core, it is possible to minimize

i. Formation damage caused by solid invasion and filtrate invasion

ii. Depth of the formation damage.

Some researchers suggest that the depth of damage due to the solid should be less than 2.5 cm (1

inch) if the drilling fluid is suitably design. Several studies, however have reported that solid

invasion exceeds 7.5 cm (3 inches) and invasion upto depth of 30 cm (12 inches). In order to

prevent solid invasion in to the large pores, the fluid system should contain a wide range of

particles to obtain a thin and low permeability filter cake. How quick the internal mud cake

forms depends on the compatibility of particle size of the mud solids and the pore size of the

formation. Particles larger than pore openings can not enter the pores and are therefore

continuously re-entrained in the annular fluid stream. Solely large particles can not be used, even

though they would not invade the pores, because the fluid loss rate would be uncontrollable and

filter cake thickness will continue to grow.

Also the particles, those are considerably smaller than the pore openings will enter the pores and

migrate freely into the formations. In order to plug and form a stable bridge at the pore openings,

the average diameter of mud solid particles should be around one third of that the largest pore

opening. Once a stable bridge is established at the pore opening and pore constriction in near

wellbore region, smaller particles will trapped in between the larger particles to form an initial

internal mud cake .This internal mud cake forms is governed by hydrodynamic forces prevailing

in mud stream which tends to deposit particles on the cake surface and the shear stress due to

mud circulation which tends to sweep particles off the cake surface. The growth of the cake

thickness will cease once the action of the two forces are in balance. The higher the annular fluid

circulation velocity and the smaller the size of the particles deposited. The thickness of filter

cake will be less and will have better properties i.e. low porosity and low permeability.

Obviously the availability of proper particle size in the mud for bridging the pore openings and

71

pore constrictions is critical in determining the quantity of spurt loss at the initial stage of initial

cake formation.

There are some rules of thumb for choosing the particle size distribution, firstly the 1/3rd rule and

secondly d1/2 relationship; Basic summary of the 1/3rd rule is that the mean particle size of the

bridging material should be greater than one third of the median pore size of the formation. The

1/3rd rule also suggests that the effectiveness of a bridging material in reducing mud solids

invasion is a function of both its concentration and particle size, as well as the pore size

distribution of the rock [Smith P.S. et al., 1996] . A median particle size of the bridging additive

equal to or slightly greater than one third of the median pore size of the formation [Suri A. et al.,

2001]. The d1/2 relationship suggests that for ideal bridging, the cumulative weight percentage of

the bridging materials should be directly proportional to the square root of their particle size

[Smith P.S. et al., 1996]. The concentration of the bridging agents must be at least 5% by volume

of the solids in the final mud mix. The D90 (90 % particles by weight are larger than this size) of

the particle size distribution of the bridging agents should be equal to the pore size of rock [Suri

A. et al., 2001].

Selection of bridging particles: Calcium carbonate is recommended as a bridging material for

fluid formulations due to the following reasons:

i. CaCO3 can be chemically removed by the acids or chelating age.

ii. Calcium carbonate is commercially available in a broad range of particle sizes. This

facilitate the selection of a blend that will efficiently bridge formation pore throats and

form a totally extra ultra low permeability filter cake on the surface of the exposed pay

zone. This adds in reducing the fluid loss rate and prevents solid invasion into the

formation when underbalanced condition is lost.

iii. The minimum concentration required of calcium carbonate is fixed 5-7% (w/v), which is

sufficient to bridge formation pore and ensure a thin high quality filter cake.

iv. The blend of Calcium carbonate products such as medium, fine and micronized grades

can be used to fit the purpose with respect to the pore size distribution of the reservoir

rock.

72

FLC 2000 versus CaCO3:

o The broad size distribution and compressibility of the aggregates means that the one

grade additive can seal a wide range of pore sizes and micro-fractures. Hence there is no

need to change the size distribution of the FLC 2000 as operation moves from formations

of one permeability to another as required in the case with CaCO3.

o Effective concentrations of FLC 2000 in drilling, completion or workover fluid range

between 3 and 8 ppb is much lower than sized calcium carbonates (30 to 40 ppb). The

optimum FLC 2000 concentration depends on the base fluid properties.

o The very low permeability barrier formed by the FLC2000 additive is much more

effective at preventing fluid invasion than conventional mud additives including sized

CaCO3.

Workover Fluid design:

Before embarking on laboratory experimental work it is essential to design sub-hydrostatic

workover fluids with low density additive so that the workover fluid density may be lowered

upto 0.65 with good rheology and to incorporate such additives in the design which shall ensure

the good rheological and filtration properties of the sub-hydrostatic underbalanced work over

fluids.

Selection of design parameters:

The designed parameters are effective mud weight should be less than 8 ppg. The fluid should

have a good rheology and filtration properties at room temperature as well as at bottom hole

temperature of 900C (selection of bottom hole temperature is according to the field X).

Selection of workover fluid type:

The design of sub-hydrostatic workover fluids for the specific field (X) has led to the selection of

three types of workover fluids. The first type fluid is based upon emulsification of non-toxic

73

oil/mineral oil in water thus reducing the specific gravity of based fluid itself. The fluid is then

incorporated with low density additive to further its specific gravity to desired level. The second

type of sub-hydrostatic workover fluid selected is a water based system incorporating low

density material for weight reduction. The rheological properties were managed by using XC

polymer, and the filtration properties were controlled by using pre-gelatinized starch (PGS). The

selection of both these additives is based upon their relative non-damaging characteristics to the

reservoir. The third type of sub-hydrostatic workover fluid is also a water based system

incorporating light weight material for density reduction, and hydroxyl ethyl cellulose (HEC)

based fluid loss controlling agent.

Selection of Additives:

This is an important step before the designed workover fluid can actually be formulated in the

laboratory. The selection of additives is based on the demanding requirement of low specific

gravity upto 0.65. Ideally the low gravity material should be chemically inert to the water and

reservoir fluids. It should be compatible with the fluid systems to which it shall be exposed

without any rheological and filtration control problems. The material should be user friendly and

should be non-damaging to the formation. One such material that has been identified is hollow

glass spheres (HGS). Since workover fluid should also have good rheological and filtration

properties suitable additives like XC Polymer for imparting viscosity to the fluid and pre-

gelatinized starch (PGS) or hydroxyl ethyl cellulose (HEC) for control of filtration properties

were incorporated into the designed sub-hydrostatic workover fluids. The selection of these

additives is based on their non-damaging characteristics for the payzone.

Workover fluid preparation:

The base fluid selected is fresh water and to this different additives are added. In one of the

compositions non-toxic oil / mineral oil has been used as a component of the based fluid. The

dosage of the additives is generally used by considering the final volume of workover fluid

including the low density material hollow glass spheres (HGS).

74

Polymer selection:

For this fluid system different polymers used are XCP, PGS, PAC (R), PAC (LV), FLC2000 and

Polyol.

Methods of evaluation of non-invasive fluids:

The following two methods have been used to evaluate the non-invasive behavior of these fluids:

Injection syringe method: A 60 ml capacity injection syringe is taken and properly packed

with 20-40 mesh quartz sand up to the mark of 30ml. Sand standardized by WSS for operations

is used in the tests. Sands of the other mesh size as per the field requirement according to the

candidate. Based on the average pore throat size of the formation can also be used. Even the

shale powder formations needing borehole stability may be used for the test. Once the syringe is

properly packed, the desired fluid is filled upto the top on the sand bed and piston is pressed

against the filled fluid. The pressure applied is manual i.e. by hand. The fluid invades the bed

and starts flowing through the pores downward .In case the normal fluid, the fluid quickly passes

through the bed and starts flowing the nozzle/opening at the bottom. But when Non-Invasive

fluid system is used, initially some invasion takes place but quickly an impermeable film on the

bed is formed and further invasion stopped completely. The distance traveled by the fluid

through the bed in a specific time is noted and comparison is made for different fluids.

Sand bed invasion test cell: A glass cell volume 630ml (approx.) with steam opening is taken.

A 60 mesh sieve is placed at bottom and properly packed with 20-40 mesh quartz sand up to the

mark of 6”. Sand standardized by WSS for operations is used in the test. However, sand of the

other mesh sizes as per the field requirement based on the average pore throat size of the

formations can also be used. Once the cell is properly packed with the sand bed, the fluid under

test is filled upto the top and a constant pressure of 100 psi pressure is applied. The fluid invades

the sand bed and start flowing downwards. In case of normal fluid (not treated with FLC 2000),

the fluid quickly passes through the bed and starts flowing the nozzle/opening at the bottom , and

entire fluid comes down even at 5 to 10 psi pressure almost immediately. However when the

fluid treated with FLC 2000 is implemented some invasion takes place but quickly an

impermeable film on the sand bed is formed and further invasion is either completely stopped or

75

its rate becomes very slow. The distance travelled by the fluid in 30 minutes at the same 100 psi

pressure is measured and a comparison is made with other fluid. For every test fresh sand is used

and sand bed is prepared.

Apparatus used: For formulation and evaluation of underbalanced workover fluid during the

project the following apparatus are used (Courtesy: IDT-Chemistry division, R&D Lab-II).

1) Electronic weighing machine

2) Hamilton beach

3) Fann VG- Viscometer with 6-speeds

4) Glass electrode pH-meter

5) API Filtration loss apparatus

6) Roller oven

7) Sand bed invasion test cell

76

Chapter 4: Results and Interpretations

. Results:

Refer table A-1, A-2, A-3 and A-4 in appendix for fluid components and their rheological properties

1) The sub-hydrostatic workover fluids for underbalanced operations, can be designed and

formulated using oil in water emulsion as the base fluid and hollow glass spheres as the

low density material (Refer table A-1). The fluid so designed is formulated with XC

Polymer and pre-gelatinized starch to impart stable rheological and filtration control

properties to the fluid. The oil used in the base fluid is non-toxic oil and provided a stable

emulsion even after hot rolling at 900C.

2) The oil in water emulsion based the sub-hydrostatic workover fluids for UBO is

formulated in four specific gravity ranges i.e. 0.84,0.78,0.72, and 0.65 depending upon

the quantity of specific gravity material i.e. hollow glass spheres added . The fluid is

found to be stable at room temperature and after hot rolling at 900C for 24 hours, it shows

good and stable rheological as well as filtration properties.

3) The second type (Refer table A-2) of oil and water emulsion based sub-hydrostatic

workover fluids (mineral oil based) for UBO is also formulated and evaluated for four

specific gravity values i.e. 0.84, 0.79, 0.73 and 0.65. The fluid is found to be stable at

room temperature and after hot rolling at 900 C for 24 hrs. and shows good, stable

rheological and filtration properties.

4) The sub-hydrostatic workover fluids for UBO are also formulated with the water as the

base fluid (Refer table A-3) using XC Polymer and Pre-gelatinized starch as suitable

formation friendly viscosifiers and filtration controlling agent respectively. The density

reduction is achieved by using low density material hollow glass spheres. Four such sub-

hydrostatic underbalanced workover fluids are formulated with specific gravity ranges

0.84, 0.78, 0.72 and 0.65 using different concentrations of HGS. The fluid is found to be

77

stable rheological properties. But these formulations do not have the desired filtration

properties as evaluated after their hot rolling at 900C for 24 hours.

5) The sub-hydrostatic workover fluids for UBO are also formulated using hydroxy ethyl

cellulose (Tylose) as the primary filtration control additive (Refer table A-4). Four sub-

hydrostatic underbalanced workover fluids are formulated having the specific gravity

0.84, 0.77, 0.70 and 0.65. The fluid is stable at room temperature and shows good

rheological and filtration properties even after hot rolling at 900C for 24 hours.

Please refer to table no.A-5 for detailed rheological properties of the non invasive fluid

formulation developed.

o The filtration loss is observed as due to unwanted overbalanced condition during the

underbalanced operations. Sl.No.1 composition of fluid provides very much filtration loss

more than 200 ml. Sl. No. 2 provides less fluid loss.

o Sl.No.3, this composition gives even though very less fluid loss.

o During the sand bed invasion test on 20/40 frac. Fluid formulation in table A-5- Sl.no.3,

with 5% micronized calcium carbonate give the invasion of 2.34 cm (100 psi) and 1.90

cm (50 psi) before this Sl.No.1 fluid composition is tested which results complete fluid

discharge from the lower nozzle.

Interpretations:

1. By adding sufficient HGS to a base fluid, one is able to lower the density of the base

fluid.

2. HGS-based fluids are homogeneous, single-phased, non-compressible, stable and have

useful rheological as well as filtration properties for use in high permeability, low

pressure producing zones.

3. Conventional solids control equipment can be used with HGS-based fluids. Field mixing

of HGS is readily accomplished.

4. HGS based fluids can help avoiding problems like differential sticking in case of when

underbalanced condition is lost.

5. FLC 2000 and MCC based non-invasive fluids can be used in underbalanced operations.

78

Fig 4.1 Sub-hydrostatic workover fluid, oil in water emulsion (Non- toxic oil)

(Refer table A-1 from appendix)

Fig 4.2 Sub-hydrostatic workover mineral oil based fluid formulation

(Refer table A-2 from appendix)

79

Fig 4.3: sub-hydrostatic workover fluids water based fluid formulation

(Refer table A-3 from appendix)

Fig 4.4: sub-hydrostatic workover fluids water based fluid formulation

(Refer table A-4 from appendix)

80

Chapter 5: Conclusion & Recommendations 5.1 Conclusion

Almost every operation of well intervention whether it is initial Completion, Recompletion

including Perforation & Stimulation. They cause irreparable damage to the reservoir resulting in

reduced productivity. It happens because of extraneous fluid invasion into the reservoir in an

overbalanced design to address operator’s genuine concern to keep the well under control.

Development of a safe technique to implement underbalanced design therefore goes well with

the proverb “Prevention is better than the Cure”. The study/reports bring out wide applicability

of underbalanced operations in the following areas:

1. Underbalanced Drilling

2. Underbalanced Workover

3. Underbalanced Perforation.

Although this technology is used to avoid the potential formation damage in the pay zone but

several times underbalanced condition is lost for keeping the well under control or other

associated down hole problems which defeats the aims and objectives of underbalanced

operations.

5.1 Recommendations

The following recommendations are made for underbalanced operations;

5.1.1 Recommendations for underbalanced drilling

Underbalanced drilling is recommended for the selected candidates where the possibility of

formation damage is significant in conventional drilling. Underbalanced drilling is recommended

to employ in severely depleted / mature fields. The sub-hydrostatic fields should be drilled

underbalanced. Non productive time is very critical factor as per the economics of any oil field

operation. The formation where the lost circulation problem and sticking pipe possibility is very

81

much, the NPT increases. Sometimes the problems are severe upto extent of deviating the

wellplan and significant increment in operating cost can be observed. The underbalanced drilling

is recommended for such type of problematic fields as per the economic consideration.

Fluid system selected for the underbalanced drilling are air/gas drilling, mist drilling, foam

drilling. The considerations during the selection of fluid system are wellbore stability as well as

air/gas volume requirement for the cuttings cleaning in air/gas drilling. The formations where the

wellbore stability is limitation to the air/gas drilling are recommended to use water based fluid or

oil in water emulsion based fluid with polymers XCP, PAC (LV), PAC(R). Polymers are used

for better rheological properties. The specific gravity should be reduced by the hollow glass

spheres upto 0.65 as according to the formulation developed (Refer tables A-1-A-4 from

appendix). The specific gravity can be minimized upto 0.65 by adding 40% (w/v) hollow glass

spheres in water. For minimizing or eliminating the possibility of formation damage when

underbalanced condition is lost, the fluid system with FLC2000, POLYOL and Micronized

Calcium Carbonate is recommended.

Safety of human being, environment and costly assets should be taken into consideration before

implementing the operation. The technology should not be implemented on a gut feel basis.

Proper handling of hollow glass spheres is recommended and when planning to use air fluid

system for operation then precaution shall be taken to ensure that explosive mixtures are not

generated at any point of operation. Jointed pipe system or coiled tubing system is

recommended to use as well control equipment. Each element of BOP should be individually

pressure tested to a high and low pressure as determined by the drilling condition anticipated.

Choke, kill line valves and the choke manifold should also be tested during this test sequence.

The accumulator performance should also be examined. The fluid volumes, pre-charge pressure

and pressure regulators are recommended to check out and adjusted prior to the spudding of each

well. After testing of BOP stack the accumulator should also be tested for minimum pressures.

Examination of accumulator and adjusting of operating parameters should be done prior to

function testing the BOP stack.

82

5.1.2 Recommendations for underbalanced workover

The underbalanced workover operation is recommended to exploit the formation to full of its

potential and to protect the reservoir from subsequent damage during each intervention.

Fluid system recommended for underbalanced workover is as like in underbalanced drilling only

the quantity of the polymer added in the low gravity fluid is adjusted as per the desired fluid

rheology.

In order to ensure safety during the workover operations; the Conventional Rig is to be replaced

by Snubbing Unit.

5.1.3 Recommendations for underbalanced perforation

After drilling a well depth upto the desired payzone, the underbalanced perforation is

recommended to achieve maximum benefits from the operation. Although this underbalanced

perforation also leave some detonation debris inside the perforating pathway but some surge

flow from reduction in near wellbore pore pressure mitigates crushed-zone damage and sweeps

some or all of the debris from perforated tunnels. High static pressure differential between

wellbore and formations provide more effective perforations. The rapid fluid influx is

responsible for perforation clean up thus it is recommended for general underbalanced

perforation.

The minimum underbalanced pressure differential is recommended to achieve ‘clean’ perforation

is

Fluid system recommended a very low gravity fluid to achieve maximum underbalanced within

the well bore stability criteria.

83

Because most of the hazards happen immediately after the perforation; Tubing conveyed

perforation (TCP) in underbalanced condition (partly emptying the well using compressor)

should invariably be used. Deep penetrating charges can be used to provide effective and deep

penetration in to the hydrocarbon bearing zones. In fact this should be made an industry standard

for depleted/ sub-hydrostatic reservoirs.

APPENDIX

Table A-1: Composition and properties of sub-hydrostatic workover fluid for underbalanced operation, oil in water emulsion (Non- toxic oil)

S/No.

Composition of

workover fluids

Temp0C Sp.Gr. pH Rheology Remark

AV PV YP Gel0 Gel10 API

F/L

1.

60% Water + 40%

Non-Toxic oil +

1% Emulsifier

At room

temperature

0.9 8.61 4.5 4 1 1 2 - A stable

workover fluid

is formulated

2. Fluid at

Sl.No.1+0.1%

XCP+ 1% PGS+

5% HGS

At room

temperature

0.84 9.15 35 30 10 3 8 - -do-

After hot

rolling at

900C for 24

hours

0.84 9.13 33 29 08 3 7 10.5

ml

-do-

3. Fluid at Sl.No.2+

5% HGS i.e.

(Total 10% HGS)

At room

temperature

0.78 9.25 40 32 16 3 8 - -do-

After Hot roll

at 900C for

24 hours

0.78 9.21 38 31 14 3 7 8.2

ml

-do-

4. Fluid at Sl.No.3+

5% HGS i.e.

(Total 15% HGS)

At room

temperature

0.72 9.35 52.5 42 21 3 8 - -do-

After Hot roll

at 900C for

24 hours

0.72 9.32 50 40 20 3 7 6.5

ml

-do-

5. Fluid at Sl.No.4+

5% HGS i.e.

(Total 20% HGS)

At room

temperature

0.65 9.35 72.5 58 29 5 9 - -do-

After Hot roll

at 900C for

24 hours

0.65 9.31 69 56 25 4 8 5

ml

-do-

Table A-2: Composition and properties of sub-hydrostatic workover fluids for

underbalanced operation, mineral oil based formulation

Sl.

No.

Composition of

workover fluids

Temp0 C Sp.Gr. pH Rheology Remark

AV PV YP Gel0 Gel10 API

F/L

1.

Mineral oil + 0.1% XCP

+1% PGS +10% HGS

At room

temperature

0.85 8.63 10.5 7 7 3 4 - -

2. Fluid at Sl.No.1+ 10%

HGS i.e. (Total 20%

HGS)

At room

temperature

0.75 8.9 20 15 10 2 4 - ---

3. Fluid at Sl .No. 2 + 5%

HGS i.e.( Total 25%

HGS)

At room

temperature

0.72 9.1 29 23 12 3 5 -

--

4. Fluid at Sl. No. 3 + 5%

HGS i.e. (Total 30 %

HGS)

At room

temperature

0.68 9.2 45 36 18 4 6 - ---

5. Fluid at Sl. No. 4 + 5%

HGS i.e. (Total 35 %

HGS)

At room

temperature

0.65 9.33 89 68 37 5 9 - ---

After hot

rolling at

900C for 24

hours

0.65 9.35 87.5 69 37 5 9 50 ml --

Sl.

No.

Composition of workover

fluids

TempoC Sp.Gr. pH Rheology Remark

AV PV YP Gel0 Gel10 API

F/L

1.

Water + 0.1% XCP + 1%

PGS +10% HGS

At room

temperature

0.87 8.95 19 11 16 3 5 -

After hot

rolling at

900C for

24hours

0.86 8.75 12.5 9 7 2 4 150 ml Very high

filtration loss

2.

Water + 0.1% XCP + 1%

PGS +20% HGS

At room

temperature

0.79 9.3 30 22 16 3 6 -

After hot

rolling at

900C for

24hours

0.77 9.1 23 17 12 2 5 165 ml Very high

filtration loss

3.

Water + 0.1% XCP + 1%

PGS +30% HGS

At room

temperature

0.72 9.5 51.5 39 25 5 9 -

After Hot

roll at 900C

for 24 hours

0.72 9.2 42.5 34 17 3 5 170ml Very high

filtration loss

4.

Water + 0.1% XCP + 1%

PGS + 40% HGS

At room

temperature

0.65 9.35 86 65 42 7 12 -

After Hot

roll at 900C

for 24 hours

0.65 9.34 66 64 14 4 7 165 ml Very high

filtration loss

Table A 3: Composition and properties of sub-hydrostatic workover fluids for underbalanced operation, water based formulation

Table A-4: Composition and properties of sub-hydrostatic workover fluids for

underbalanced operations, water based formulation

Sl.

No.

Composition of

workover fluids

Temp oC Sp.Gr. pH Rheology Remark

AV PV YP Gel0 Gel10 API

F/L

1.

Water + 0.5%

Tylose + 10 %

HGS

At room

temperature

0.86 9.30 21.5 14 15 2 4 - -

After hot

rolling at

900C for 24

hours

0.86 9.30 37.5 20 35 3 6 20 ml

2. Water + 0.5%

Tylose + 20% HGS

At room

temperature

0.77 9.20 31 21 20 3 5 -

After hot

rolling at

900C for 24

hours

0.77 9.10 52.5 25 55 4 8 15.0ml

3.

Water + 0.25%

Tylose + 30% HGS

At room

temperature

0.70 9.28 53 30 46 3 6 -

After Hot

roll at 900C

for 24 hours

0.70 9.25 55 42 26 2 6 7 ml

4. Water +0 .25%

Tylose + 40% HGS

At room

temperature

0.65 9.49 55 50 10 2 5 -

After Hot

roll at 900C

for 24 hours

0.65 9.42 60 52 16 3 5 5ml

Sl.

No.

Composition of workover

fluids

Temp0 C Sp.Gr. pH Rheology Remark

AV PV YP Gel0 Gel10 API

F/L

1.

60% Water + 40% Non-

Toxic oil + 1%

Emulsifier+0.1%

XCP+0.7% PAC

(LV)+0.1% PAC (R)+

NaOH

At room

temperature

0.93 9.32 50.5 37 27 7 9 Very

much

Filtration

loss was

very much

2. 50% Water +50% LTMO +

emulsifier(1%) + 0.4%

XCP + 0.7% PAC (LV)+

0.2% PAC(R) + 1.2% FLC

2000 + 0.1% MgO + KOH

At room

temperature

0.92 9.30 52.5 43 19 6 8 14ml Sub-

hydrostatic

workover

fluid

3. Water +3% KCl +

0.45%XCP +1.2% PAC

(LV) + 0.3% PAC(R) +

1.2% FLC 2000 +

3% Polyol + 5 % MCC

+0.1% MgO+

KOH

At room

temperature

0.75 9.25 59 28 62 15 11 -

After Hot

roll @

1000C for

18 hours

0.72(with

foam)

1.02

(without

foam)

9.18 50 28 44 9 8 8ml

Table A-5: Water and oil based Non damaging / Non Invasive fluid formulation for underbalanced workover operation

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