The document discusses oil recovery methods including primary, secondary, and tertiary (enhanced oil recovery) techniques. Primary recovery uses natural reservoir pressures to produce 10-25% of oil initially in place. Secondary recovery maintains pressure through water or gas flooding to produce additional oil. Tertiary/enhanced oil recovery (EOR) uses sophisticated thermal or non-thermal methods like gas injection to extract more oil, becoming more important as oil prices rise. The document focuses on different driving mechanisms in primary recovery and introduces EOR methods.

1. OIL AND NATURAL GAS CORPORATION LTD.
SUB SURFACE TEAM, AHMEDABAD ASSET
CHANDKEDA, AHMEDABAD-382005
Application of Water Shut-Off and Profile Modification Jobs
by Polymer Gel treatment for increasing the Productivity of
the well
Report
Submitted in partial fulfilment of the requirement of
Bachelor of Technology in
Petroleum Engineering
IIT (ISM) DHANBAD
Submitted By
Himanshu Chhabra & Akanksha Sidar
Under the Guidance of
Mr.B.P SINGH
DGM (Reservoir), ONGC

2. OIL AND NATURAL GAS CORPORATION LTD.
SUB SURFACE TEAM, AHMEDABAD ASSET
CHANDKHEDA, AHMEDABAD-382005
CERTIFICATE
This is to certify that Himanshu Chhabra and Akanksha Sidar students of
Indian Institute of Technology (ISM), Dhanbad have successfully
completed their internship on “Water Shut-Off and Profile Modification
Jobs” under my supervision at SST ONGC, Ahmedabad Asset from 12th
December 2016 to 06th
January, 2017 as a part of the Winter internship
Program in their 3rd
Year B.Tech course in Petroleum Engineering, 5th
Semester.
MR.B.P.SINGH
DGM (Reservoir)
SST ONGC,
Ahmedabad Asset

3. UNDERTAKING
We, Himanshu Chhabra & Akanksha Sidar third year student of B. Tech
(Petroleum Engineering) of Indian Institute of Technology(ISM), Dhanbad
have done our Winter Internship at Sub Surface Team ONGC,
Ahmedabad Asset from 12th December 2016 to 6th
January, 2017 on the
topic "Water Shut-Off Jobs and Profile Modification Jobs".
We undertake the following
That we will not disclose any confidential information (proprietary
information) received from the ONGC to any other person, company,
organization, and firm; as we know that confidential information cannot be
sold, exchanged, published or disclosed to anybody by any way including
photocopies or reproduced materials etc. without prior written consent of
ONGC.
That we will keep confidentiality to the highest extent in order to avoid the
disclosure or use of the information received during internship.
That we will not publish/use data provided by ONGC anywhere in India or
outside India
That if we are proved to be guilty for the disclosure of the confidential or
proprietary information, ONGC has the sole discretion the right for the
reimbursement of damages borne due to the disclosure.
(Signature)
Date:
Place: Ahmedabad

4. ACKNOWEDGEMENT
Firstly, we would like to thank Dr.T.K Naiya for his great efforts in
arranging our training at ONGC Ahmedabad asset under sub-surface
team.
We take this opportunity to acknowledge tire relentless and generous
support of Mr. B.P Singh, DGM (R) for his guidance as our mentor guiding
us through his valuable insights and suggestions during the internship.
His encouragement made the experiments possible and his explanations
gave us a thorough understanding of Chemical EOR processes.
Himanshu Chhabra & Akanksha Sidar
3rd
year B. Tech
IIT(ISM),Dhanbad

5. CONTENTS
Certificate
Undertaking
Acknowledgement
List of Figures
Chapter 1: Introduction 01
Oil recovery
1. Primary Recovery…………….…………………………………………….01
2. Secondary Recovery……………………………………………………….04
3. Tertiary Recovery…………………………………………………………..05
Chapter 2: Enhanced Oil Recovery 06
1. IOR vs EOR………………………………………………………………...06
2. Thermal Methods………………………………………………………….07
3. Non-Thermal Methods………………………………...………………….09
Chapter 3: Water Shut Off and Profile Modification Job 14
1. Gel Treatment for Conformance Control…………………………………14
2. Water shut Off………………………………………………………………20
3. Profile Modification…………………………………………………………23
4. Gel Conformance Improvement Treatment……………………………...26
5. Gel Type……………...……………………………………………….…….26
6. Gel Treatment sizing for Production Well………………………………..28
Chapter 4: Case Study 30
1. Introduction…………………………………………………………………30
2. Experimental………………………………………………………………..31
3. Conclusions………………………………………………………………...34
Chapter 5: Field Implementation of Water Shut off Techniques 39
1. Introduction…………………………………………………………………39
2. Gel Optimization…………………………………………………………...39
3. Project Planning and Execution…………………………………...….….40
4. A Field …………………………………..……………………………….…41
5. J Field………………………………..…………………………………......43
Chapter 6 Emulsion Formation Study 46
1. Introduction……………….…………………………………………..…...46
2. Theory………………….……………………………………………..…....46
3. Observations………..……………………………………….……….……47
4. Result ……………………….……………………………………………..48
Chapter 7: Reference 50

6. LIST OF FIGURES
Figure 1: Fluid saturations and the target of EOR
Figure 2: General Classification of EOR Methods
Figure 3: Three stages of Cyclic Steam Stimulation
Figure 4: Transition zone and concentration profile of the solvent in miscible flooding
Figure 5: Worldwide water oil ratio distribution
Figure 6: Water control method for increasing well productivity
Figure 7: Good and bad water
Figure 8: Casing leaks
Figure 9: Flow behind the pipe
Figure 10: Water coning in both vertical and horizontal wells
Figure 11: A production well both with and without coning
Figure 12: Watered-out layer (A) with and (B) without crossflow
Figure 13: Fractures or faults from a water layer surrounding a (A) vertical well or a (B)
horizontal well
Figure 14: Fractures or faults between an injector and a produce
Figure 15: Water Shut Off Techniques
Figure 16: Injection Pattern of the Jhalora Wells
Figure 17: WHP and Halls plot
Figure 18: Cumulative Injection vs tracer concentration(JH-65)
Figure 19: Cumulative injection vs tracer concentration in produced water
Figure 20: Production Performance of the producer wells of A-127, A-121(injector wells) PM
Job done in Oct’16
Figure 21: Production Performance of the producer wells of A-108(injector well) PM Job
done in Nov’16
Figure 22: Production Performance of the producer wells of A-26(injector well) PM Job
done in Nov’16
Figure 23: Production Performance of the wells in which WSO Job was carried out
Figure 24: Production Performance curves of the producer wells of J-98(injector well) PM
Job done in May’16
Figure 25: Surfactant Solution added to oil
Figure 26: Alkali solution added to oil
Figure 27: Alkali Surfactant added to oil in different concentration
Figure 28: Comparison of Surfactant, Alkali Solution, Alkali Surfactant and Solvents

7. 1
CHAPTER 1
Introduction
Oil Recovery
During the life oil wells, production process usually passes three stages. Primary
recovery uses the natural source of energy. Pumps and gas lifting are involved in the
primary recovery. The main purpose of secondary recovery process is to maintain the
reservoir pressure by either a natural gas flooding or water flooding. The rise in world
oil prices has encouraged the producers to use the new technical developments.
Enhanced oil recovery (EOR) is a collection of sophisticated methods, to extract the
most oil from a reservoir. EOR can be divided into two major types of techniques:
thermal and non-thermal recovery. Each technique has a specific use in a certain type
of reservoirs. Among non-thermal techniques is the gas flooding, where gas is
generally injected single or intermittently with water. Flue gas and nitrogen have only
limited application as agents of a miscible displacement in deep and high pressure
reservoirs. Although new development processes such as water alternating gas
(WAG) or Simultaneous water alternating gas (SWAG), are implemented, there are
still some problems encountered by EOR engineers. This paper is discussing the last
updating in this field. Index Terms—Enhanced oil recovery (EOR), miscible flooding,
nitrogen injection, water alternating gas (WAG).

8. 2
1. Primary Recovery
When an oil field is first produced, the oil typically is recovered as a result of expansion
of reservoir fluids which are naturally pressured within the producing formation. The
only natural force present to move the oil through the reservoir rock to the wellbore is
the pressure differential between the higher pressure in the rock formation and the
lower pressure in the producing wellbore. Various types of pumps are often used to
reduce pressure in the wellbore, thereby increasing the pressure differential. At the
same time, there are many factors that act to impede the flow of oil, depending on the
nature of the formation and fluid properties, such as pressure, permeability, viscosity
and water saturation. This stage of production, referred to as "primary recovery,"
recovers only a small fraction of the oil originally in place in a producing formation,
typically ranging from 10% to 25%.
There are basically six driving mechanisms that provide the natural energy necessary
for oil recovery:
 Depletion Drive
Natural gas dissolved in solution is the source of energy for depletion drive reservoir.
As oil is produced, its pressure drops. Once the bubble point pressure is achieved, the
natural gas will come out of liquid and forms bubbles which would expand as fluid
pressure reduces further. The expanding bubbles supports production till they reach
critical point saturation where they join together and begin to flow as single gas phase.
Because of their low viscosity, the gas phase will flow rapidly to wellbore. This results
in massive drop in reservoir pressure and this finite source is depleted and well ceases
to flow.
Hence, we try to keep the gas till the critical saturation by injecting less expensive fluid
to replace hydrocarbons being produced.
The general characteristics of depletion drive reservoir are-
1. Pressure depletion is rapid.
2. Gas Oil ratio (GOR) increases rapidly and declines at later stage.
3. Water Oil ratio is zero or negligible.
4. Ultimate recovery is very low (5-25%).
The low recovery from this type of reservoirs suggests that large quantities of oil
remain in the reservoir and, therefore, depletion-drive reservoirs are considered the
best candidates for secondary recovery applications.
 Gas Cap Drive
Gas-cap-drive reservoirs can be identified by the presence of a gas cap with little or
no water drive. Due to the ability of the gas cap to expand, these reservoirs are
characterized by a slow decline in the reservoir pressure. The natural energy available
to produce the crude oil comes from the following two sources:
 Expansion of the gas-cap gas.

9. 3
 Expansion of the solution gas as it is liberated.
Characteristics of a gas cap drive are-
1. Pressure decline is less steep as compared to depletion drive because
there is a support of gas cap.
2. GOR of well will be increasing with time.
3. GOR of wells near the gas oil contact will be higher.
4. Water production or influx would be negligible.
5. Recovery factor is 15-35%
 Water drive
Water drive reservoirs are identified by the presence of an active water aquifer. In
active water drive, water in aquifer replaces the hydrocarbon removed and reservoir
pressure is maintained at or near to its original value. Oil production is maintained at
a rate at which the water will replace the hydrocarbons. Pressure maintenance is done
either by withdrawing oil at the rate of replacement by aquifer or by injecting water to
support the aquifer. As the invading water reaches the well and the volume of water
produced to the oil increases, the well must be shut in or recompleted at the higher
interval.
Characteristics of water drive reservoirs are-
1. Pressure decreases very slowly.
2. Water Oil ratio increases with time.
3. GOR remains almost constant for quite a long time.
4. Ultimate recovery is 40- 70 %.
 Compaction drive reservoir
Withdrawl of liquid or gas from a reservoir results in reduction in the fluid pressure and
consequently an increase in the effective or grain pressure. The increased pressure
between the grains will cause the reservoir to compact and this in turn can lead to
subsidence at the surface.
 Combination drive reservoir
The driving mechanism most commonly encountered is one in which both water and
free gas are available in some degree to displace the oil towards the producing wells.
This means that two combination of driving forces can be present in combination drive.
The most common type of drive encountered, therefore, is a combination-drive
mechanism.
The general characteristics of combination drive reservoirs are-
1. Reservoir pressure falls gradually with time.
2. GOR increases with time.
3. Water cut increases with time.

10. 4
4. A substantial percentage of the total oil recovery may be due to the depletion-
drive mechanism. The gas-oil ratio of structurally low wells will also continue to
increase due to evolution of solution gas throughout the reservoir, as pressure
is reduced.
5. Ultimate recovery from combination-drive reservoirs is usually greater than
recovery from depletion-drive reservoirs but less than recovery from water-drive
or gas-cap-drive reservoirs. Actual recovery will depend upon the degree to
which it is possible to reduce the magnitude of recovery by depletion drive.
 Gravity Drainage drive
Mechanism of gravity drainage occurs in petroleum reservoirs as a result of
differences in densities of the reservoir fluids. Due to long periods of time involved in
the petroleum accumulation and migration process, it is assumed that the reservoir
fluids are in equilibrium. If they are in equilibrium, then gas oil water contact should be
essentially horizontal.
The general characteristics of gravity drainage reservoirs are-
1. Presence of low GOR from structurally low well which is caused by migration
of the evolved gas up structure due to gravity segregation of fluids.
2. There is formation of secondary gas cap in the reservoir which initially was
under saturated.
3. Increasing GOR in structurally high wells. Therefore, it is not profitable to drill
well at those areas.
4. There is little or no water production. Water production is indicative of a water
drive.
5. Rate of pressure decline is varying. It depends principally on the amount of gas
conversion.
6. Wells where the gas is conserved and reservoir pressure is maintained, the
reservoir would be operating under combined gas cap drive and gravity
drainage mechanism.
2. SECONDARY RECOVERY
After the primary recovery phase, many, but not all, oil fields respond positively to
"secondary recovery" techniques in which external fluids are injected into a reservoir
to increase reservoir pressure and to displace oil towards the wellbore. Secondary
recovery techniques often result in increases in production and reserves above
primary recovery. Waterflooding, a form of secondary recovery, works by re-
pressuring a reservoir through water injection and "sweeping" or pushing oil to
producing wellbores. The water used for injection is brackish, non-potable water that
is co-produced with the oil or obtained by drilling a well into a water bearing formation.
Through waterflooding, water injection replaces the loss of reservoir pressure caused
by the primary production of oil and gas, which is often referred to as "pressure
depletion" or "reservoir void age." The degree to which reservoir void age has been

11. 5
replaced through water injection is known as "reservoir fill up" or, simply as "fill up." A
reservoir which has had all of the produced fluids replaced by injection is at 100% fill
up. In general, peak oil production from a waterflood typically occurs at 100% fill up.
Estimating the percentage of fill up which has occurred, or when a reservoir is 100%
filled up, is subject to a wide variety of engineering and geologic uncertainties. As a
result of the water used in a waterflood, produced fluids contain both water and oil,
with the relative amount of water increasing over time. Surface equipment is used to
separate the oil from the water, with the oil going to pipelines or holding tanks for sale
and the water being recycled to the injection facilities. In general, in the Mid-Continent
region, a secondary recovery project may produce an additional 10% to 20% of the oil
originally in place in a reservoir.
3. TERTIARY RECOVERY
Tertiary Oil Recovery is also a supplementation of natural reservoir energy; however,
it is defined as that additional recovery over and above what could be recovered from
primary and secondary recovery methods. Typical recoveries are 5-20% OIP after
primary and secondary recovery (average 13%). The process used for reducing the
Reservoir Oil Saturation ROS is known as tertiary recovery process.

12. 6
CHAPTER 2
Enhanced Oil Recovery
1. IOR vs EOR
Nearly 2.0 × 1012 barrels (0.3 × 1012 m3) of conventional oil and 5.0 × 1012 barrels (0.8
× 1012 m3) of heavy oil will remain in reservoirs worldwide after conventional recovery
methods have been exhausted. Much of this oil can be recovered by Enhanced Oil
Recovery (EOR) methods, which are part of the general scheme of Improved Oil
Recovery (IOR).
The terms EOR and IOR have been used loosely and interchangeably at times. IOR,
or improved oil recovery, is a general term which implies improving oil recovery by any
means. For example, operational strategies, such as infill drilling and horizontal wells,
improve vertical and areal sweep, leading to an increase in oil recovery. Enhanced
oil recovery, or EOR, is more specific in concept, and it can be considered as a subset
of IOR. EOR implies a reduction in oil saturation below the residual oil saturation
(ROS). Recovery of oils retained due to capillary forces (after a waterflood in light oil
reservoirs), and oils that are immobile or nearly immobile due to high viscosity (heavy
oils and tar sands) can be achieved only by lowering the oil saturation below ROS.
Miscible processes, chemical floods and steam based methods are effective in
reducing residual oil saturation, and are hence EOR methods.
The target of EOR varies considerably for the different types of hydrocarbons. Figure
1 shows the fluid saturations and the target of EOR for typical light and heavy oil
reservoirs and tar sands. For light oil reservoirs, EOR is usually applicable after
secondary recovery operations, and the EOR target is ~45% OIP. Heavy oils and tar
sands respond poorly to primary and secondary recovery methods, and the bulk of
the production from such reservoirs come from EOR methods.
Figure 1: Fluid saturations and the target of EOR
Many EOR methods have been used in the past, with varying degrees of success, for
the recovery of light and heavy oils, as well as tar sands. A general classification of
Assuming Soi = 85% PV and Sw = 15% PV( )
Tar sandsHeavy oilsLight oils
Water
EOR Target
% OIP100
Water
EOR Target
% OIP45
Secondary
30% OIP
Primary
% OIP25
Water
EOR Target
90% OIP
Secondary
5% OIP
Primary
5% OIP

13. 7
these methods is shown in Figure 2. Thermal methods are primarily intended for heavy
oils and tar sands, although they are applicable to light oils in special cases. Non-
thermal methods are normally used for light oils. Some of these methods have been
tested for heavy oils, however, have had limited success in the field. Above all,
reservoir geology and fluid properties determine the suitability of a process for a given
reservoir. Among thermal methods, steam-based methods have been more
successful commercially than others. Among non-thermal methods, miscible flooding
has been remarkably successful, however applicability is limited by the availability and
cost of solvents on a commercial scale. Chemical methods have generally been
uneconomic in the past, but they hold promise for the future. Among immiscible gas
injection methods, CO2 floods have been relatively more successful than others for
heavy oils.
2. Thermal Methods
Thermal methods have been tested since 1950’s, and they are the most advanced
among EOR methods, as far as field experience and technology are concerned. They
are best suited for heavy oils (10-20° API) and tar sands (≤10° API). Thermal methods
supply heat to the reservoir, and vaporize some of the oil. The major mechanisms
include a large reduction in viscosity, and hence mobility ratio. Other mechanisms,
such as rock and fluid expansion, compaction, steam distillation and visbreaking may
also be present. Thermal methods have been highly successful in Canada, USA,
Venezuela, Indonesia and other countries.
Figure 2: General Classification of EOR Methods

14. 8
 Cyclic Steam Stimulation (CSS)
Cyclic steam stimulation is a “single well” process, and consists of three stages, as
shown in Figure 3. In the initial stage, steam injection is continued for about a month.
The well is then shut in for a few days for heat distribution, denoted by soak. Following
that, the well is put on production. Oil rate increases quickly to a high rate, and stays
at that level for a short time, and declines over several months. Cycles are repeated
when the oil rate becomes uneconomic. Steam-oil ratio is initially 1-2 or lower, and it
increases as the number of cycles increase. Near-wellbore geology is important in
CSS for heat distribution as well as capture of the mobilized oil. CSS is particularly
attractive because it has quick pay-out, however, recovery factors are low (10-40%
OIP). In a variation, CSS is applied under fracture pressure. The process becomes
more complex as communication develops among wells.
Figure 3: Three stages of Cyclic Steam Stimulation
 Steamflooding
Steamflooding is a pattern drive, similar to waterflooding, and performance depends
highly on pattern size and geology. Steam is injected continuously, and it forms a
steam zone which advances slowly. Oil is mobilized due to viscosity reduction. Oil
saturation in the swept zone can be as low as 10%. Typical recovery factors are in the
range 50-60% OIP. Steam override and excessive heat loss can be problematic.
 In Situ Combustion
In this method, also known as fire flooding air or oxygen is injected to burn a portion
(~10%) of the in-place oil to generate heat. Very high temperatures, in the range of
450-600°C, are generated in a narrow zone. High reduction in oil viscosity occurs near
the combustion zone. The process has high thermal efficiency, since there is relatively
small heat loss to the overburden or underburned, and no surface or wellbore heat
loss. In some cases, additives such as water or a gas is used along with air, mainly to
enhance heat recovery. Severe corrosion, toxic gas production and gravity override
are common problems. In situ combustion, has been tested in many places, however,
very few projects have been economical and none has advanced to commercial scale.
The main variations of in situ combustion are:
– Forward combustion,
Cold oil
Steam

15. 9
– reverse combustion,
– High pressure air injection.
In forward combustion, ignition occurs near the injection well, and the hot zone moves
in the direction of the air flow, whereas in reverse combustion, ignition occurs near the
production well, and the heated zone moves in the direction counter to the air flow.
Reverse combustion has not been successful in the field because of the consumption
of oxygen in the air before it reaches the production well. High pressure air injection
involves low temperature oxidation of the inplace oil. There is no ignition. The process
is being tested in several light oil reservoirs in the USA.
3. Non-Thermal Methods
Non-thermal methods are best suited for light oils (<100 cp). In a few cases, they are
applicable to moderately viscous oils (<2000 cp), which are unsuitable for thermal
methods. The two major objectives in non-thermal methods are:
– lowering the interfacial tension,
– improving the mobility ratio.
Most non-thermal methods require considerable laboratory studies for process
selection and optimization. The three major classes under non-thermal methods are:
miscible, chemical and immiscible gas injection methods. A number of miscible
methods have been commercially successful. A few chemical methods are also
notable. Among immiscible gas drive processes, CO2 immiscible method has been
more successful than others.
 Miscible Flooding
Miscible flooding implies that the displacing fluid is miscible with the reservoir oil either
at first contact (SCM) or after multiple contacts (MCM). A narrow transition zone
(mixing zone) develops between the displacing fluid and the reservoir oil, inducing a
piston-like displacement. The mixing zone and the solvent profile spread as the flood
advances. The change in concentration profile of the displacing fluid with time is
shown in Figure 5. Interfacial tension is reduced to zero in miscible flooding, therefore,
Nc = ∞. Displacement efficiency approaches 1 if the mobility ratio is favourable (M <
1). The various miscible flooding methods include:
– miscible slug process,
– enriched gas drive,
– vaporizing gas drive,
– high pressure gas (CO2 or N2) injection.

16. 10
Figure 4: Transition zone and concentration profile of the solvent in miscible flooding.
 Miscible Slug Process
It is an SCM (single contact miscible) type process, where a solvent, such as propane
or pentane, is injected in a slug form (4-5% HCPV). The miscible slug is driven using
a gas such as methane or nitrogen, or water. This method is applicable to sandstone,
carbonate or reef-type reservoirs, but is best suited for reef-type reservoirs. Gravity
segregation is the inherent problem in miscible flooding. Viscous instabilities can be
dominant, and displacement efficiency can be poor. Reef-type reservoirs can afford
vertical gravity stabilized floods, which can give recoveries as high as 90% OOIP.
Several such floods have been highly successful in Alberta, Canada. Availability of
solvent and reservoir geology are the deciding factors in the feasibility of the process.
Hydrate formation and asphaltene precipitation can be problematic.
 Enriched Gas Drive
This is an MCM type process, and involves the continuous injection of a gas such as
natural gas, flue gas or nitrogen, enriched with C2-C4 fractions. At moderately high
pressures (8-12 MPa), these fractions condense into the reservoir oil and develop a
transition zone. Miscibility is achieved after multiple contacts between the injected gas
and the reservoir oil. Increase in oil phase volume and reduction in viscosity contrast
can also be contributing mechanisms towards enhanced recovery. The process is
limited to deep reservoirs (>6000 ft) because of the pressure requirement for
miscibility.
 Vaporizing Gas Drive
This also is an MCM type process, and involves the continuous injection of natural
gas, flue gas or nitrogen under high pressure (10-15 MPa). Under these conditions,
the C2-C6 fractions are vaporized from the oil into the injected gas. A transition zone
develops and miscibility is achieved after multiple contacts. A limiting condition is that
the oil must have sufficiently high C2-C6 fractions to develop miscibility. Also, the
injection pressure must be lower than the reservoir saturation pressure to allow

17. 11
vaporization of the fractions. Applicability is limited to reservoirs that can withstand
high pressures.
 CO2 Miscible
CO2 Miscible method has been gaining prominence in recent years, partly due to the
possibility of CO2 sequestration. Apart from environmental objectives, CO2 is a unique
displacing agent, because it has relatively low minimum miscibility pressures (MMP)
with a wide range of crude oils. CO2 extracts heavier fractions (C5-C30) from the
reservoir oil and develops miscibility after multiple contacts. The process is applicable
to light and medium light oils (>30° API) in shallow reservoirs at low temperatures.
CO2 requirement is of the order of 500-1500 sm3/sm3 oil, depending on the reservoir
and oil characteristics. Many injection schemes are in use for this method. Particularly
notable among them is the WAG (Water Alternating Gas) process, were water and
CO2 are alternated in small slugs, until the required CO2 slug size is reached (about
20% HCPV). This approach tends to reduce the viscous instabilities. Cost and
availability and the necessary infrastructure of CO2 are therefore major factors in the
feasibility of the process. Asphaltene precipitation can be a problem in some cases.
 N2 Miscible
This process is similar to CO2 miscible process in principle and mechanisms involved
to achieve miscibility, however, N2 has high MMP with most reservoir oils. This method
is applicable to light and medium light oils (>30° API), in deep reservoirs with moderate
temperatures. Cantarell N2 flood project in Mexico is the largest of its kind at present,
and is currently producing about 500 000 B/D of incremental oil.
 Chemical Flooding
Chemical methods utilize a chemical formulation as the displacing fluid, which
promotes a decrease in mobility ratio and/or an increase in the capillary number. Many
commercial projects were in operation in the 1980’s, among which, some were
successful, but many were failures. The current chemical floods activity is low, except
in China. The future holds promise because of the high demand for energy, and also
because of the advancement in technology. Considerable experience and
understanding have been gained from the past chemical floods projects. Economics
is the major deterrent in the commercialization of chemical floods. It must also be
noted that the technology does not exist currently for reservoirs of certain
characteristics. The major chemical flood processes are polymer flooding, surfactant
flooding, alkaline flooding, micellar flooding and ASP (alkali-surfactant-polymer)
flooding. Other methods tested include emulsion, foam and the use of microbes, but
their impact has not been significant on EOR production thus far.
 Polymer Flooding
Water soluble polymers, such as polyacrylamides and polysaccharides are effective
in improving mobility ratio and reducing permeability contrast. In most cases, polymer

18. 12
flooding is applied as a slug process (20-40% PV) and is driven using dilute brine.
Polymer concentration is between 200-2000 ppm. There were many polymer floods in
the past, but recoveries were less than 10% in most cases. The major limitations
include loss of polymer to the porous medium, polymer degradation and in some
cases, loss of injectivity. One of the common reasons for the failure of polymer floods
in the past was that it was applied too late in the waterflood, when the mobile oil
saturation was low. The process will be more effective if applied earlier during a
waterflood, at water breakthrough, for example, when the oil saturation is above the
residual oil saturation.
Currently polymer flooding pilot projects are being tested in Sanand Field of
Ahmedabad asset of ONGC in India.
 Surfactant Flooding
Surfactants are effective in lowering interfacial tension between oil and water.
Petroleum sulfonates or other commercial surfactants are often used. An aqueous
surfactant slug is followed with a polymer slug, and the two chemical slugs are driven
using brine. There were a number of surfactant floods in the past, but they were
largely ineffective, mainly due to excessive surfactant loss to the porous medium.
Surfactant adsorption and reactions with the rock minerals were severe in some
cases. Treatment and disposal of emulsions were also of concern.
Currently Pilot projects for Surfactant flooding are showing great results in the Kalol
field of Ahmedabad asset ONGC, India
 Alkaline Flooding
In alkaline flooding an aqueous solution of an alkaline chemical, such as hydroxide,
carbonate or orthosilicate of sodium, is injected in a slug form. The alkaline chemical
reacts with the acid components of the crude oil and produces the surfactant in situ.
IFT reduction is the main mechanism. Spontaneous emulsification may also take
place. Drop entrainment or drop entrapment may occur depending on the type of
emulsion formed, which may enhance or diminish the recovery. Alkalis can cause
changes in wettability [25], however, large concentrations are required for wettability
alterations. Field results have been discouraging (RF 0-3% OIP). The process is
complex to design due to the various reactions that take place between the alkaline
chemical and the reservoir rock and fluids.
 Micellar Flooding
Micellar flooding has been more successful in the field than other chemical flooding
processes. The main components of this method are a microemulsion slug (also
known as a micellar slug) and a polymer slug. These two slugs are driven using brine.
Microemulsions are surfactant-stabilized, oil-water dispersions with small drop size
distributions (10-4 to 10-6 mm). Microemulsions can be “miscible” with reservoir oil as
well as water. The two chemical slugs are designed such that ultra-low IFT (10-2 mN/m
or lower) and favourable mobility ratio prevails during the most part of the
displacement. The process has been tested in 45 field projects, and it has been proven
that the method is successful in banking and producing the residual oil left after a

19. 13
waterflood. Recovery factors ranged between 35-50% OIP in field projects. However,
economics was unattractive due to the high cost of chemicals, the requirement of small
well spacing, the high initial expense and the considerable delay in response.
Moreover, the geology and conditions in many candidate reservoirs (high salinity,
temperature and clay content) are unsuitable for the application of micellar flooding.
The process holds potential, and deserves to be re-evaluated under the current
economic conditions. Scaling groups have been derived for micellar flooding, which is
a valuable tool for laboratory evaluation to reduce the risk in the field application of the
process.
 ASP Flooding
In the ASP process, the Alkali reacts with acidic components in the oil and produce
petroleum soaps (surfactants) which in turn recover residual oil. Most fields application
of alkaline flooding were not successful as anticipated. Some of the important reasons
for poor field results are alkali loss due to reaction with the rock matrix and hard
formation brines, low acid content of oil, and lack of mobility control, especially with
viscous oil. The Alkali consumption by the rock matrix occurs due to silica dissolution,
clay transformation and ion exchange reactions. As result of the alkali loss, the
concentration of hydroxyl (oH-) ions significantly decreases and the efficiency of
alkaline flooding diminishes. One way to compensate for alkali loss to the rock is to
increase the concentration of the alkali in the slug. But, it may have an adverse effect
on the IFT between oil and chemical slug. The salinity of system would dramatically
affect the IFT response. If the salinity is too low, the surfactant tends to concentrate in
the aqueous phase. If it is too high, the surfactant is driven primarily into the oil phase.
The ideal situation is to have the surfactant concentrated at the oil water interface
where it can be more effective. This may occur only over a very narrow range of
concentration. Therefore, as alkali concentration is increased the salt level increases
beyond optimum and IFT increases. At very low concentrations, insufficient quantity
of surfactants is formed and IFT increases. Also, it enhances rock dissolution and may
cause scale formation in the production wells. To avoid the adverse effect on interfacial
tension when using high alkali concentration, a low concentration of surfactant can be
added to the system to effectively shift the optimum salinity window to a higher level
at which a middle phase emulsion in alkaline flooding. Combination of the alkaline
agents with the surfactants gives more encouraging IFT reductions (1000 fold
reduction). Therefore, coupling of alkali-surfactant and polymer takes advantages of
the unique benefit of three process and eliminates some of negative aspects of each
process. Another mechanism for oil recovery is the wettability reversal from oil-wet to
water-wet and that occurs at high ionic strength. The ASP slug had a high ionic
strength which drives the synthetic surfactant out of the aqueous phase. The
surfactant is adsorbed onto the rock surface and as a result, the wettability of the rock
changes. The trapped oil becomes more mobile and more oil can be recovered.
Currently ASP flooding is being used at the kalol Field of the Ahmedabad asset of
ONGC.

20. 14
CHAPTER 3
Water Shut Off (WSO) and Profile Modification(PM)
1. Gel Treatment for Conformance Control
 Water problem
An average of 210 million barrels of water accompanies 75 million barrels of oil
produced daily. This ratio is even higher in the US, at 7:1, as shown in Figure 5. Water
problem is worse in the North Sea oil field, where 222 million tons of water are
produced with 4 thousand tons of oil. The economic lives of many wells are shortened
because of the excessive production cost associated with water production. These
expenses include lifting, handling, separation, and disposal. The unwanted water uses
up the natural drive and lead to possible abandonment of the production well.
Excessive water increases the risk of formation damage, produces a higher corrosion
rate, and increases emulsion tendencies. It may also form a hydrate because the water
and gas are not produced in a proper ratio. The excessive water produced in water
drive production wells is typically a result of a coning zone within the rock or from
vertical fractures which extend into bottom water drive.
Figure 5: Worldwide water oil ratio distribution
One barrel of water has the same production cost as one barrel of oil. The annual cost
required to dispose of the excess water is estimated to be 40 billion dollars worldwide;
it is between 5 and 10 billion dollars in the US. Reducing the amount of water produced
would help in decreasing not only the chemical treatments but also the separation cost
associated with the production process. It would also decrease the costs of artificial
lift requirements. Water shut-off treatments can be applied to both carbonate and
sandstone formations as well as fractured and matrix permeability reservoirs.
Well productivity and potential reserves have been increased by the water control
method. As illustrated in Figure 6, the water oil ratio increases as the production

21. 15
increases within a mature oil well. The water control method needs to be applied when
the water-to-oil ratio reaches an economical limit with high excessive water handling
costs. The WOR will drop below the economic limit and continue producing oil after
the production rate is reduced. Thus, the water control method extends an oil well’s
life.
Figure 6: Water control method for increasing well productivity
Sweep water is good water produced by either injection wells or active aquifers that
sweep the oil from the reservoir. Effective water pushes oil through the formation and
toward the wellbore. It cannot be shut-off without shutting off the oil. Bad water
produces an insufficient amount of oil, increasing the WOR until it is over the
acceptable limit. The good and bad water concept is depicted in Figure 7.
Figure 7: Good and bad water
 Water control problems
Near Wellbore Problem. Six near well bore problems have been listed below:
a) Casing leaks problem.
The water that flows to the wellbore through the casing fissure arrives from either
above or below the production zone. Casing leaking create an unexpected increase in
the water producing rate, as demonstrated in Figure 8. These leaks can be classified
into one of two types: casing leaks with flow restrictions and casing leaks without flow
restrictions. Gel treatments offer an effective solution to casing leaks with flow
restrictions. The leaks examined in this study moved through a small aperture breach
(e.g. pinholes and tread leaks in the piping). The pipe fissure was less than
approximately 1/8-inch; the flow conduit was less than approximately 1/16-inch. In
contrast, Portland cement is a better treating method for casing leaks without flow

22. 16
restrictions. These leaks are created by a large aperture breach in the pipe and a large
flow conduit.
Figure 8: Casing leaks
b) Flow behind the pipe.
Two situations contribute to flow behind the pipe (Figure 9) flow behind the pipe without
flow restrictions and flow behind the pipe with flow restrictions. Cement is an effective
method for flow behind the pipe without flow restrictions. A lack of primary cement
behind a casing creates a large aperture, thereby producing a large flow channel. The
flow conduit is approximately greater than 1/16inch. Flow behind the pipe with flow
restrictions is caused by cement shrinkage during the well’s completion. A flow conduit
less than 1/16-inch is formed along with small apertures.
Figure 9: Flow behind the pipe
c) Barrier breakdowns.
A new fracture can be formed near the wellbore by either fracture breaking through
the impermeable layer or utilizing acids to dissolve the channels. The pressure
difference across the impermeable layer will drive the fluid migration throughout the
wellbore. This type of conformance problem can be related to the stimulation process
sometimes.
.

23. 17
d) Channels behind the casing.
Bad connections between not only the formation and the cement but also the cement
and the casing can create water channels behind the casing. A bad cement job, cyclic
stresses, and post-stimulation treatments contribute to these issues. Another cause of
this issue is the space behind the casing created by the sand production. Either a high
strength squeeze cement in the annulus or a lower strength gel-based fluid placed in
the formation can be used to stop the water channel (Bailey et al., Water Control).
e) Inappropriate completion.
Inappropriate completion can immediately create unwanted water production. This
issue can also cause both coning and cresting near the wellbore. A sufficient
geological survey is quite important before the completion of the project.
f) Scale, debris and bacterial deposits.
Scale, debris, and bacterial deposits can obstruct and alter the non-hydrocarbon flow
to undesired zone.
Reservoir Related Problems. Six reservoir related problems have been listed
below:
a) Coning and cresting
Coning is a production problem that occurs either when bottom water or a gas cap gas
infiltrate the perforation zone near a wellbore. This behaviour reduces oil production.
The interface shape for coning is different between a vertical well and a horizontal
well, as depicted in Figure 10. The coning interface shape in a horizontal well is similar
to a crest. The horizontal well will produce a smaller amount of undesired secondary
fluids under comparable coning conditions. The hydrocarbon flow rate will greatly
decrease after the cone breaks into the producing interval, which will also lead to a
dramatic increase of water and gas rate, as illustrated in Figure 11. The reservoir
pressure will be depleted shortly after the gas cone breaks through. This depletion
may cause oil well shut-in.
Figure 10: Water coning in both vertical and horizontal wells

24. 18
Figure 11: A production well both with and without coning
b) Watered-out layer with and without crossflow
Both the water crossflow and the pressure communication in a watered-out layer with
crossflow (Figure12A) occur between high permeability layers without impermeable
barrier isolation. Either an injection well or an active bottom water can serve as the
water source. A gel treatment should not be considered when radial crossflow occurs
between adjacent water and hydrocarbon strata. A gelant will crossflow into oil
producing zones, away from the wellbore. Thus, they do not effectively improve the
conformance problem. A conformance improvement technology (e.g. polymer
flooding) should be used to improve oil viscosity.
Watered-out layer without crossflow (Figure 12B) is a common problem. It is usually
associated with multilayer production in a high-permeability zone with impermeable
barriers isolation. This problem is easy to treat; either a rigid, shut-off fluid or a
mechanical method can be applied in either injection wells or producing wells. Coiled
tubing is recommended as a placing method.
Figure 12: Watered-out layer (A) with and (B) without crossflow
c) Fingering.
Viscous fingering can cause poor sweep efficiency during the oil recovery flooding
process. Viscosity will form when the oil has a higher viscosity than the displacing fluid
has.

25. 19
d) Out of zone fractures
Fracturing is one of the main causes for reservoir heterogeneity. Both hydraulic
fractures and natural fractures can cause water production problems. These problems
can be treated by gel placement. The following three challenges, however, must be
addressed.
 The gel injection volume is difficult to determine.
 Treatment may shut-off the oil producing zone. Thus, a post-flush treatment
needs to be applied to maintain productivity near the wellbore.
 The flowing gel must be tolerated to resist flow-back after gel placement.
Figure 13: Fractures or faults from a water layer surrounding a (A) vertical well or a
(B) horizontal well
e) Channelling through a high permeability zone.
A high permeability zone will lead to early breakthrough. The displacing fluid will
bypass lower permeability zones and flow through high permeability zones. This
phenomenon leads to low sweep efficiency and a high WOR. It is most common in
reservoirs with either an active water drive or a water-flooding-treated reservoir.
f) Fracture between the injection and producing wells.
Injection water is easy to breakthrough. It can cause excessive water problem in
production wells with naturally fractured formation between injection wells and
producing wells, as shown in Figure 14. Gel treatments offer the best solution because
they have limited penetration to matrix rock. Bullhead injection through injection well
can be applied with the gel treatment.
Figure 14: Fractures or faults between an injector and a produce

26. 20
2. Water shut off (WSO)
Water shut-off is defined as any operation that hinders water to reach and enter the
production wells. Water production is one of the major technical, environmental, and
economical problems associated with oil and gas production. Water production not
only limits the productive life of the oil and gas wells but also causes several problems
including corrosion of tubular, fines migration, and hydrostatic loading. Produced water
represents the largest waste stream associated with oil and gas production. Moreover,
the production of large amount of water results in
(a) the need for more complex water–oil separation
(b) rapid corrosion of well equipment’s
(c) rapid decline in hydrocarbon recovery and
(d) ultimately, premature abandonment of the well while others use chemical to
manage unwanted water production.
In many cases, innovative water-control technology can lead to significant cost
reduction and improved oil production. Water shut-off without seriously damaging
hydrocarbon productive zones by maximizing permeability reduction in water–source
pathways, while minimizing permeability reduction in hydrocarbon zones is the target
for oil and gas operators. In mature fields, oil and gas wells suffer from high water
production during hydrocarbon recovery. High water production represents a serious
threat to the quality of the environment due to water disposal, and is a growing concern
in the petroleum industry. Today, a full range of solutions is available for virtually any
type of produced water challenge. A variety of techniques and tools is available to
appropriately analyze well bore and reservoir characteristics. Most importantly,
diagnosing the problem so as to determine which treatment will provide the best
overall technical and economical solution. Water Shut-Off (WSO) treatments in
production wells are a routine part of standard well service work. We now use cement
squeezes or mechanical isolation methods with high success rates for
"straightforward" WSO targets. By contrast, the perception of chemical treatments
such as polymer gels for WSO has been one of relatively high risk. Therefore, we have
tended to use gel-based methods as a final option (short of side-tracking the well) for
WSO when standard methods are obviously inapplicable or have already been tried
without success. These target wells have been complex, and some had mechanical
limitations due to long-term shut-in or failed previous WSO attempts using plugs or
cement. We have often been exploring new territory, and have had to consider many
issues.
 Water shut-off techniques
Water shut-off is defined as any operation that hinders water to reach and enter
production wells. There exist countless number of techniques such as polymer and
polymer/gel injection, different types of gel systems, organic/metallic cross linkers, and
a combined between them, mechanical solution, cement plug solution and other
hundreds of different mechanical and chemical methods for water shut-off.

27. 21
a) Well configuration and Well completions
The number of injection and production wells required to produce a field suggests the
approach of selecting the optimum pattern and spacing. Different well pattern models,
including line-drive, five, seven and nine spot, normal or inverted, could be developed
for different well spacing under different well and reservoir conditions. Designing
optimal well configuration, completions and replacements using new technologies
starting with drilling techniques until the reservoir simulation, has the capability to
increase oil recovery and reduce water production. The strategies of drilling and
completion options are numerous. Some of the basic concepts are:
Drilling a vertical well with open or cased and perforated completion either production
or injection well; Drilling a horizontal and/or deviated well, or perhaps multilateral wells;
Extending the use of an old well by re-perforating new productive zones.
b) Mechanical solution
In many near wellbore problems, such as casing leaks, flow behind casing, rising
bottom water and watered out layers without crossflow, and in the case of bottom
water beginning to dominate the fluid production, the perforations are sealed-off with
a cement-squeeze, packer or plug. The well is re-perforated above the sealed zone,
and oil production is resumed. This process is continued until the entire pay zone has
been watered out. This method is one of the easiest ways to control water coning.
c) Mechanical and cement treatment
Using squeeze cement alone is not sufficient. This is attributed to the fact that the size
of the standard cement particles restricts the penetration of the cement into channels,
fractures and high permeable zones, only about 30% success is reported.
The easiest method to control water coning when bottom water begins to dominate
the fluid production is to seal off the perforations with a cement-squeeze, packer or
plug. The well is then re-perforated above the sealed zone, and oil production is
resumed. This process is continued until the entire pay zone has been watered out.
However, these techniques require separated and easily identifiable oil and gas
producing zones. Where possible, mechanical zone isolation by cement squeezes or
plugging type gels can be the easiest way to shut off water coning from watered out
layers. Very often excessive water-cuts can be reduced by re-completing the well or
by placing mechanical devices to isolate the water producing zones. These solutions
however, are expensive and can cause in micro-layered formations, the loss of
volumes of hydrocarbons.
d) Chemical solution
Chemical treatments require accurate fluid placement, and including polymer/gel
injection, different types of gel systems, organic cross linkers, metallic cross-linkers
and combined between them as means of improving flooding efficiency are needed in
heterogeneous reservoirs to reduce water production and improve oil recovery.

28. 22
Figure 15: Water Shut Off Techniques
 Water shut off job
a) Sealing gels
Sealing gels block a water producing interval. Sealing gels compete with cements or
packers. Polymer gels have been widely used to reduce water production. The gels
are intended to block the pore space in both the matrix and fractures of water
producing zones. The polymer gel systems designed for conventional fractured
reservoirs are usually partially cross-linked during placement and have high initial
viscosity. This is done to reduce the leak off the gelant into the matrix.
b) Relative permeability modification (RPM)
Relative permeability modification (RPM) is a property that is exploited during certain
oilfield water-shutoff (WSO) treatments and a property whereby many water-soluble
polymers and aqueous polymer gels reduce the permeability to water flow to a greater
extent than to oil or gas flow. Refs. 1-20 are illustrative literature references that
discuss the RPM phenomenon. RPM WSO treatments are applicable to both oil and
gas production wells. RPM is also referred to as disproportionate permeability
reduction (DPR). Some practitioners reserve the term “DPR” for relatively strong
polymer gels that impart a large degree of disproportionate permeability reduction and
a large reduction in water permeability. These practitioners reserve the term “RPM”
for systems such as solutions of water-soluble polymers or relatively “weak” gels that
impart more subtle disproportionate permeability reductions and more subtle
reductions in water permeability. However, in this paper, the terms RPM and DPR will
be considered synonyms. At times in the literature, DPR and RPM have also been
referred to as “selective permeability reduction” and “selective permeability blocking.”

29. 23
Why RPM/DPR WSO Treatments Are Attractive:
The reason that there is so much active interest in the petroleum industry regarding
bulkheadable DPR water-shutoff treatments is that they normally do not require the
use of mechanical zone isolation during treatment-fluid placement. In contrast, when
applied to wells of matrix-rock reservoirs involving radial flow, conventional (relatively
strong and total-fluid-shutoff) polymer-gel WSO treatments normally require the use
of mechanical zone isolation during treatment placement.44 Mechanical zone isolation
often requires costly workover operations. In addition, the use of mechanical zone
isolation during water-shutoff-treatment placement is normally not feasible when the
well possesses a slotted-liner or gravel-pack completion or when the well involves a
sub-sea tieback flow line. Presently, RPM/DPR WSO treatments are a technology that
is in vogue within the industry, and many individuals and organizations are attempting
to develop and exploit these treatments.
RPM/DPR Does Occur:
When numerous of the early RPM/DPR WSO treatments did not perform as well as
expected, a number of oil-industry professionals questioned whether RPM/DPR
actually occurs. As it turns out, it does.1-43 Thus, the challenge is to learn when,
where, and how RPM/DPR can be successfully employed in WSO treatments.
3. Profile Modification
When flooded out channels and productive low permeability zones are well isolated
from each other, mechanical methods that alter the production profile can be used.
Mechanical methods include the use of selective completion configurations and
squeeze cementing. When flooded-out channels and paths of least resistance are not
well isolated from one another, mechanical methods may be less effective and
somewhat less efficient In many cases, die optimal profile modification strategy must
rely on the inherent interaction between the treatment fluids, the reservoir fluids and
the reservoir rock into which the treatment is placed.
For purposes of this discussion, any strategy by which fluids are diverted from their
path of least resistance is classified as a profile modifier. The simplest examples of
these are water-alternating gas techniques or polymer floods which make use of the
inherent interaction between fluids and the rock characteristics
Profile modification plays very important role in increasing oil recoveries from matured
oilfields during displacement type enhanced oil recovery process. During water
flooding, water sweeps through high permeability sections or fractures and fracture
network present in the heterogeneous reservoirs leaving back oil in the low
permeability sections leading to low oil recovery and early water breakthrough. This
water production also causes several difficulties in oil industries and increases the
operating cost of the well. The profile modification is a technique of emplacement of
gel into highly permeable channel, fractures and fracture networks which block the
fractures and fracture network or reduce permeability of high permeable channels and
allow diversion of injected water through low permeability section which were upswept
earlier leading to improvement in oil recovery.

30. 24
Initially, polyacrylamide had been used in both water flood injection well and
production well to control injection profile or water production. However, permeability
gradually increases when retained polymer expose to large throughputs of water.
Apparently, the retained polymer washed out from retention sites by prolonged
exposes of flowing fluid. Hence, crosslinked polymer gels have been used in the oil
industries as they are rigid and more stable. The formation of gel from the reaction of
polymer and crosslinkers lead to a system with increased mechanical and thermal
stability. Several varieties of crosslinked polymer gels are used for the purpose of
profile modification jobs in the oilfields. The partially hydrolyzed polyacrylamide and
xanthan gum biopolymer are generally crosslinked with inorganic and organic
crosslinkers to produce three dimensional structures of polymer gels. Inorganically
crosslinked gel results from ionic bonding between the negatively charged carboxylate
group of polymer and multivalent cations of inorganic crosslinkers. The gelation
mechanism of organic crosslinkers is due to covalent bonding, which is much more
stable over a wide range of temperature. This is possible because crosslinking done
by covalent bonding is much more stable than ionic bonding.
Gel treatment for improved production Well performance
Typically, gel treatments are one of the most aggressive types of conformance control
or profile modification. Gel technology is more aggressive since it can totally block
certain porous features associated with the porous media and thus, in a very drastic
manner, divert fluid flow from areas of low drag to areas of much greater drag (high
permeability to lower permeability). There are many examples of where this can occur
and how this is achieved. Some of the situations where this occurs will next be
discussed. Following this discussion, some of the parameters which should be
considered in gel treatment applications for production well performance are reviewed.
 Fractures
Fractured reservoirs can exhibit high productivity coupled with serious technica1
challenges. The major challenge is due to the fact that the permeability through the
fractures is orders of magnitude larger than the permeability through the matrix. Once
the hydrocarbons have been recovered from the fracture then the remaining target for
recovery is in the tighter matrix. Preferentially, this is not where the injection fluids want
to flow and therefore some means of modifying their natural proclivity to flow through
the fractures must be implemented. If successful. the overall recovery can be
significantly higher than that expected from a fractured reservoir.
 High Permeability Streaks
In contrast to fractures which may have very localized separation of the porous media.
high permeability streaks are better represented by a natural flow unit or layer which
has a much lower resistance to fluid flow than oilier layers. Examples abound in the
literature where this bas occurred. The Pembina reservoir in Alberta. Canada is a
prime example where the upper layer permeability is in the range of 200 mD and
contains approximately 10% of the total oil in place. The lower flow unit, although
having permeability approximately 10 to 50 times lower than the upper flow unit,
contained the bulk of the oil. In such a case, fluid flowed preferentially through the

31. 25
upper zone and very little of it was diverted into the lower zone. With properly designed
gel strategies, the target from a reservoir such as this is much greater than without.
 Bottom Water and Coning
A Common problem for both gas and oil reservoirs is coning. In one example recently
addressed by the authors, a prolific gas well, having potential to produce 100 BSCF
was shut in after only hours of production due to bottom water coning. The rate was
subsequently reduced to a level which mitigated the coning problem but which reduced
revenues by 60%. In such a case, if the bottom water could be controlled, the prize
would be significant.
 Worm Holes
In heavier oil reservoirs with unconsolidated porous media, any pressure surge from
the injector can result in a parting of the formal). In such cases, there are literally holes
which develop in the rock through which fluid flow is very easy. Unless these holes are
blocked and flow is diverted away from these holes, conformance can be very A
number of examples exist in the literature where this has occurred but one of the most
obvious was proven on the basis of a dye &acer test performed on a heavy oil reservoir
in Elk Point, Alberta. In this case, a dye was injected into the injector and within 30
minutes the tracer was being observed in the offset producers. Based on the volume
of dye injected and the time and distance traveled, the path of least resistance present
in this reservoir was adequately described as a large pipe connecting the injector to
the producer. Unless controlled, this problem can result in abandonment of many
producing wells.
 RPM
The absence of profile modification, water injected into the reservoir will go into the
high-permeability zones and will bypass the oil-saturated, low-permeability zones.
reservoir simulation of a relative permeability modifier (RPM) used for profile-
modification improvement in injection wells. By injecting the RPM within the high-
permeability zones, subsequent injected water will be diverted into low-permeability
zones to improve the sweep efficiency of the waterflooding project.
RPM is a water-soluble relative permeability modifier initially developed for water
control in production wells. The polymer functions by adsorption onto rock surfaces
and effectively reduces water flow with little or no damage to hydrocarbon flow. These
treatments are extremely easy to mix and pump, and require no post-job shut-in time.
RPM was evaluated in 5- and 10-ft sandpacks to investigate parameters, such as
depth of penetration, diversion properties, treatment injection rate, and polymer
concentration. Laboratory results indicate RPM can effectively penetrate through a 10-
ft sand pack, providing permeability reduction to water throughout the length of the
porous media. In addition, excellent diverting properties were observed while
bulkheading the treatment in sandpacks in parallel with significant permeability
contrast.
In addition, a 3-D numerical simulator was used to evaluate the performance of the
RPM system under different scenarios and varying parameters, such as (1)

32. 26
permeability contrast between injection zones, (2) presence/absence of shale barriers
between injection zones, and (3) treatment volumes, among others.
4. Gel Conformance Improvement Treatment
Gel treatment, acting as a plugging agent for near wellbore treatment, success rate to
water shut off is around 75%. When gel treatment has been injected into formation, it
can divert fluid flow from water channels to formation matrix. Fluid prefer to flow from
high permeability and low oil saturation zone, it will normally bypass low permeability
zones with high oil saturation. Gel treatment can change this behaviour, and to
enhance oil production and improve flood sweep efficiency. Gel treatment can reduce
production operation cost by lower water production rate. In the oil field, gel treatment
can be applied to conformance related problems such as water or gas shutoff
treatment, sweep improvement treatment, squeeze and recompletion treatments or
aged wells abandonment treatment.
5. Gel Type
An appropriate gel selection is important to water shutoff treatment; it will affect
treatment result directly. Gel with greater strengths can be applied in reservoir with
large fractures, weaker gel will be used in reservoir with less extensively fracture or
matrix with lower productivity.
a) Polymer Gels.
Polymer gel treatment is the most common and effective gel treatment application in
reservoir. Polymer gel can flow through fractures and also strong to withstand high
pressure difference near wellbore. It can be placed in high permeable with high water
saturation, to reduce water permeability and block the water channels. Crosslinked
polymer gel can be applied to production wells with excessive water or gas flow; it can
also apply to injection wells with poor injection profiles. Polymer goes through
crosslinking fist and then forms a solid gel with time and temperature. There have two
type of crosslinker to polymer: organic crosslinker and metal ions crosslinker, the most
common use for metal ions crosslinker is chrome-based crosslinker.
Metal ions crosslinkers are contain Al3+, Cr3+ and Cr6+. Crosslinker with Al3+ is hard
to control or delay the crosslinking time. Chromium (III)-Carboxylate/Acrylamide-
Polymer Gels is also known as CC/AP gels. CC/AP gel can be both used as water
shutoff treatment and sweep improvement treatment. CC/AP is acrylamide-polymer
crosslinked with chromium (III) carboxylate complex. CC/AP gel can be applied in a
broad pH range, and also has a wide range of gel strengths. CC/AP gel has wide range
of controllable gelation-onset delay time, but sensitive to high temperature reservoir.
The upper limit for CC/AP gel is around 300 oF.
The disadvantage for chrome-based crosslinkers are less remaining time during
injection and sometimes tend to set up earlier than desired, particularly at
temperatures above 175 oF. For high reservoir temperature or oxidative degradation,
Metal ions crosslinked polymers are less likely to use. Organic crosslinker polymer is
an environmental friendly system. It took less job to mix and pump to the field. Organic
crosslinker system reacts more predictable to change of reservoir temperature,
component concentration, brine type, salinity and pH values. Those characters make
organic crosslinking polymer gel easier to control and to understand during the treating

33. 27
process. Compare to chrome based polymer gel, organic crosslinkers lasts longer time
than tradition polymer gel with it deep sealing properties. From the laboratory test data
result, organic crosslinker can penetrate into the formation eight times as far as
traditional chrome-based polymer; it can completely seal off the formation.
Conformance problems suitable
for polymer gels
Matrix conformance problems
Without crossflow
With crossflow
Yes
Challenging—must place very
deeply
Fracture conformance problems
Simple
Network—intermediate intensity
and
directional trends
Network—highly intense
Hydraulic
Depends—case-by-case basis
Yes
Often not
Yes
Coning
Water and gas via fractures
Water and gas via matrix reservoir
rock
Yes
No
Behind pipe channeling
Casing leaks
Yes, for microflow channels
Yes, for microflow channels
b) Silicate Gels.
Silicate gel used to be the most wildly applied inorganic conformance improvement
technique years ago. But because of the low injectivity in reservoir matrix rock and
reduced gel strength with increased gelation onset time, silicate gel is not being widely
applied recently.
c) Relative Permeability Modifiers (RPM)
The purpose of RPM is to reduce water flow permeability while don’t have meaningful
changes to hydrocarbon flow. Upswept and low water saturation fracture zone are the
most favourable condition for RPM application. And also, RPM can be used to use to
wells with water drive problem, low mobility ratio problem or layered reservoir with
distinct vertical
permeability barriers.
Advantages Gel Treatment over Cement Treatment.
Gelents can penetrate into porous rock while cement can only seal rock surface.
Cement can only seal near wellbore channels or plug normal permeability rock,
sufficient injection pressure is for significant distance by fracturing or parting the rock
or sand. Cement may not sufficiently seal the channel if cement does not adhere
strong enough to the rock. And also, cement cannot penetrate into narrow channels.

34. 28
There have three advantage gels over cement listed below; two of them are
summarized:
 Gel can have formed an impermeable and deeper barrier inside porous media
 Gel can flow into narrow channels behind pipe.
 Gel can form a non-permanent plug and can be remove easily.
 Gel treatment is cheaper than cement because of reduced crew and rig time.
6. Gel Treatment sizing for Production Well
Gel treatment sizing design is an unsolved problem in oil and gas industry so far. A lot
of failure field cases demonstrated facts that wrong gel treatment sizing estimate is
one of the main failure water shut off treatment reason. Several strategies as follows
have been used to gel treatment sizing design in oil field, they are summarized from
300 producing well water shut off treatment. But comparing and considering all the
methods to make final decision is always better than just relying on a single method:
1. Gel injection volume based on minimum volume. The effective way to estimate
the capacity of the well is let the fluid producing for more than 24 hours in a
pumped off condition, the total volume for gel treatment is the maximum daily
rate. The maximum daily rate is also refers as minimum volume. This strategy
will be based on individual field, well specifics and the history data and
experience. This method gel better result in natural fractured reservoir.
Normally no less than minimum volume needs to be pumped, but for fractured
well, 2 or 3 times the minimum gel treatment volumes need to be pumped to fill
more fractures near wellbore.
2. Gel injection volume based on distance. It’s difficult to predict gel treatment’s
penetration. One of the numerical methods of sizing a gel treatment is used
radial flow calculation. According to the experience, 50 to 60 food radius of rock
originating from the wellbore will be used for calculation. Another numerical
method is using a minimum of 50 and up to maximum of 200 barrels of gel per
perforated food. This method is productivity related, if the well has high
productivity, a factor close to 200 barrels of gel per perforated food will be used;
if the well has low productivity than close to 50 barrels of gel per perforated food
will be applied.
3. Gel injection volume based on well response. Treating pressure is a good
indicator in injection process. During the injection process, if the treating
pressure starts low and increase gradually at the beginning, but then increase
rapidly after barrels of gel has been pumped. That shows gel already plugged
high permeability water producing zone and no more gel is required. but if no
rapidly increase for treating pressure during the injection process, injection
volume don’t need to readjusted and keep the injection pressure below previous
established maximum pressure.
4. Gel injection volume based on experience in a given field. Previous treatment
field data is the most reliable source compare to methods above. Operators
need to keep on tracking of gas, oil, water fluid level after gel treatment. A good
before and after treatment formation profile records are good reference to
evaluate treatment success, help the interpretation of result. Future treatment
modification and improvement will rely on those experiences.

35. 29
CHAPTER 4
Case Study
Objective: Control of preferential movement of the polymer in one
direction by using organic crosslinking polymer
1. Introduction
In case of a heterogeneous reservoir, having high and low permeable zones, profile
modification using gelled polymer treatment ensures diversion of displacing fluid
towards upswept area thereby enhancing oil recovery. The treatment can be done in
producer wells also for suppressing of water or gas coning and to increase production
by controlling excessive water or gas cut. The design of gel treatment, i.e., quantity of
material injected, depth of emplacement, gel performance, etc., is a function of specific
characteristics of a reservoir and the applicable gel system. Profile modification using
polymer-aluminium citrate gel has been successfully done in Jhalora field (pay IX+X)
both in injection and production wells of polymer pilot. The results have been analysed
and discussed in this paper.
Brief description of the process
In the case of aluminium citrate gelation technique (also known as chelated aluminium
technique) slug of polymer solution is injected in the formation followed by slug of
aluminium ion chelated with citrate ion with small water spacer in between. This is
followed by another slug of polymer solution. The aluminium ion, as a result of
controlled generation of metal ion in solution, attaches to adsorb first layer of polymer
and acts as a bridge to the second polymer layer. The process helps in creating a
lattice-like network of polymer molecules in the porous medium increasing long term
effectiveness of the treatment. The same sequence of injection can be repeated for
obtaining the desired resistance effect. It has been observed that if soluble aluminium
(Al+3) at low pH is used for cross linking, reaction is rapid and it is difficult to disperse
the aluminium uniformly in polymer. Al+3 is also readily adsorbed by the reservoir and
in-depth penetration is unlikely. By chelating the aluminium with citrate in-depth
penetration is improved. The strength of gelation and depth of penetration in the
reservoir depends upon the formation characteristics and also upon the concentration
and slug size of the chemicals being used and the same can be optimised in the
laboratory. The degree of permeability reduction, therefore, can be controlled by the
number of times each slug is injected and by the size of slug selected.
Profile modification in polymer pilot wells
Polymer flooding on pilot scale in Jhalora horizon IX+X envisaged polymer injection in
an inverted five spot pattern with one injector in the centre, four producers and one
monitoring well between injector and one of the producers as indicated in Fig. 1.

36. 30
Salient reservoir and fluid properties of the field are shown in Table 1. Results of pre-
pilot studies (PLT, Pulse test, Pressure transient test, etc.) indicated existence of high
permeability channel between injector (#66) and one of the producers (#64). After work
over job, injection on pilot scale commenced with the injection of Ammonium
Thiocyanate tracer (1130 ppm). This was followed by pre-flushing of the reservoir with
tube well water. As the injection continued, tracer breakthrough in monitoring well
(#65) was observed after about 2600 rn3 volume of cumulative injection attaining peak
(80 ppm) after 6300 m3 of cumulative injection. Tracer breakthrough was also
observed in one producer (#64). The early breakthrough of tracer confirmed existence
of high permeability streak in this direction that was earlier suspected during pulse
test. Subsequently, polymer breakthrough was also observed in the monitoring well.
By that time 18667 m3 of fluid had been injected in the formation, which included 1856
m3 of the polymer solution and the rest water. At this stage further injection stopped
for profile modification.
2. Experimental
After initial screening for polymer and aluminium citrate combination, laboratory
experiments on standard, as well as native cores, were conducted for optimization of
slug size, concentration of chemicals, sequence of injection, etc., and it was found that
sequential injection of polyacrylamide polymer (Pusher 1000 in present case) and
aluminium citrate with small water spacer in between would be most suitable. It was
observed in the laboratory that if the pH of Al-citrate solution is raised to 8-9 and pH
of entire solution after mixing with polymer is also maintained at 8, good quality of gels
are formed. Process developed in the laboratory involved injection of an alkaline pre-
flush (for conditioning of reservoir and for maintaining pH), preferably sodium
carbonate, followed by injection of polymer solution (1000 ppm conc.) at pH 8- 9. This
was followed by small volume of water spacer and finally injection of aluminium citrate
solution at pH 9. A small volume of water spacer was recommended at the end to clear
the well bore. A retention time of three days was given after injection of the fluids.
Water spacer between the polymer and the aluminium citrate was given to separate
the two from mixing in the injection line and to clean the sand face to avoid possibility
of gel formation before entering the reservoir. To prevent incomplete mixing of fluids
the treatment was broken into three cycles with larger proportion of fluids injected in
the first cycle.
Field design of treatment plan
Optimisation of depth of treatment
The optimization of depth of treatment was done on the basis of fractal model
developed for the pilot in which entire pay thickness was divided into four layers of
resistivity assuming that resistivity is proportional to permeability. The assumption was
made on the basis of laboratory observations, where high permeability cores indicated
higher oil saturations.
Calculation of effective permeability of layer after treatment
Using the steady state flow equations and standard nomenclature, formula for
calculating effective permeability of layer after treatment was derived as follows:

37. 31
2 ln(re/rw)
K= --------------------------------------------------------------------------------
{ln(re1 /rw) / k1 +ln(re/re 1) /k2+ln(re/re2) /k2+ln(re2/ rw) /k3}
Where,
K = Effective permeability after treatment
re1 & re2 = Depth of treatment
k1 & k3 =Resulting permeability after treatment
k2 =Permeability of untreated zone
re = Depth of investigation, 75 m in present case
rw =Well bore radius, 0.07 m.
Calculation of flow rates in individual layers
It was assumed that the treatment will reduce the permeability’s of higher permeability
layers to the extent that it matches with the permeability values of tighter part (upto
distance of treatment). The resultant average effective permeability of each layer was
calculated and based on this the flow rate (O) and flow rate/ meter (Q/ H) in each layer
was calculated. For optimum profile modification, the 0/1-1 of injection fluid in each
layer is supposed to be same at the well bore. For fourlayer model, considered in
present case, the optimum value of this ratio should be 25%. Any deviation from this
value either way (+ve or -ve) was added to get total deviation.
One side treatment
In the first case, only the injector was considered for treatment. For no treatment, the
total deviation was found to be 60. The results indicated that beyond 5 m depth of
treatment, the deviation was not reducing considerably but the chemical requirement
increased significantly thereby increasing the cost of treatment.
Both sides treatment
The second case was considered taking both injector and producer for equal distance
of treatment. The total deviation for no treatment was 60. After treatment, it came down
to 13 for 5 m of treatment and 6 for 20 m of treatment. This also indicated treatment
giving best results upto 5 m.
Well wise design
To be on the safer side treatment for injection well was considered for 10 m away from
the well bore and for producers it was taken as 7 m. The quantity required percentage
of polymer, aluminium citrate and spacer for five wells optimised in the following order:
Polymer 66.6%, conc 1000 ppm
Spacer 6.25%, Water
Al-Citrate 20.8%, 200 ppm and
Spacer 6.25%, Water

38. 32
Field implementation
On the basis of laboratory analysis, design for field implementation was prepared to
carry out profile modification job in injector for blocking high permeability streak, as
well as four producers, so that producing WOR could be reduced. Well head pressure
response with respect to cumulative injection during different cycles of treatment and
Hall's plot, which is a convenient way of analysing response (WHP X Del.t) with
respect to cumulative injection, of the four wells have been shown in Fig. 17
The first well taken for treatment was the injector (#66). As indicated in Fig. 17, WHP
in the beginning was 30-33 kg/cm2, which increased up to 44-52 kg/cm2 at the end of
the second cycle of treatment and came down to 42-44 kg/cm2 at the end of the third
cycle of treatment.
Injection pressure response in #3 (producer) indicated a different trend. WHP in the
beginning of treatment was 20 kg/cm2 which decreased to 56 kg/cm2 with
advancement of injection and increased again upto 35-40 kg/cm2 at the end of first
cycle of injection. The well head pressure increased upto 46 kg/cm2 during spacer
injection. The behaviour was analyzed and it was decided to skip the second Cycle of
the treatment and complete with the third cycle. The pressure in the beginning of the
third cycle was 20-22 kg/cm2 but increased upto 48-50 kg/cm2 at the end.
The remaining two producers (#64 & #67) were taken up for treatment in the end. In
#64 WHP during pre-flushing was 78 kg/cm2 and it stabilised at 40- 44 kg/cm2 at the
end of first cycle. During second cycle of injection WHP increased upto 60 kg/cm2 and
at this stage injection was stopped. WHP at the end of third cycle increased up to 68-
76 kg/cm2. The WHP trend was different in case of #67. During pre-flushing WHP was
8-10 kg/cm2 and no increase was observed in it at the end of first cycle of treatment.
However, WHP at second and third cycle of injection were 32-36 kg/cm2 and 38-43
kg/cm2 respectively.
After completing the profile modification treatment, regular injection of polymer started
and out of four producers three were kept open for production. The producer (#64)
showing early breakthrough of tracer and polymer was kept closed.
The increase in well head pressure during treatment indicated decrease in reservoir
permeability. The same was confirmed by subsequent analysis of results of pulse test,
plt studies and PBU/PFO studies. Table 2 indicates permeability values determined in
four wells before and after treatment.
Tracer response in production wells after treatment
Prior to profile modification tracer had broken through much earlier in monitoring well
(#65) attaining peak after only 6500 rn3 of cumulative injection (Fig. 18). After
treatment, before starting polymer injection, as a first step 10000 ppm of ammonium
thiocyanate tracer was injected to assess. The success of treatment. Polymer injection
then continued and completed as per the scheme. The same had to be followed by
chase water injection, which is in progress. As indicated in Fig. 19, the tracer has
broken through in all the four producers well after almost identical volume of
cumulative injection of about 25000 to 30000 m3. The delay in tracer breakthrough

39. 33
time and breakthrough in all the four producers clearly indicates increase in polymer
contact area. Tracer breakthrough after almost identical volume of cumulative injection
further indicates almost uniform sweep in all the directions. In fact, one of the
producers (#64), in the direction of channel, that was kept closed for about a year,
when opened for production indicated presence of tracer in the effluent after about
30000 rn3 of cumulative injection.
3. Conclusions
Rise in well head pressure during injection and subsequent pulse test after treatment
indicated significant decline in reservoir permeability and success of aluminium citrate
treatment. Delayed tracer breakthrough in producers at almost identical volume of
injection indicates increase in total swept area as well as uniform movement of flood
toward four producers. The process can be tried in other wells also where similar
problems exist.
Field
Horizon
Lithology
Depth
Thickness(Hp)m
Porosity
Permeability
Temperature
Oil Viscosity
Jhalora
IX+X
Sandstone
1300m
10m
32%
3-10 Darcy
85oc
4.5Cp(at res.
Temp)
Table 1: Salient Reservoir and Fluid Properties of the Field
Table 2: Permeability on the Basis of Pulse Test Data
Well no.
Permeability
(Before Treatment)
Permeability
(After Treatment)
3 12.3 1.5
64 20.4 3.5
67 7.5 3.0
69 8.7 1.8

40. 34
Figure 16: Injection Pattern of the Jhalora Wells
Figure 17: WHP and Halls plot

41. 35
.
Figure 18: Cumulative Injection vs tracer concentration(JH-65)
Figure 19: Cumulative injection vs tracer concentration in produced water

42. 36
CHAPTER 5
Field Implementation of Water Shut-Off Techniques
1. Introduction
A asset encompasses a total of 27 hydrocarbon producing fields, out of these some
are operating under depletion drive with pressure maintenance by water injection (K,
N, W, L, G) while others are operating under active/partial aquifer support (V, J and
S). It is noticed that oil production in major producing sands of major contributing fields
is declining due to either injection water break-through or excessive water production
due to coning/channeling. The wells of Sand K-VA of K Field which has very good
permeability and Sand K-IX of W Field are facing breakthrough of injection water. In
the Sand K-IX+X of V Field water fingering from bottom is occurring and in the major
producing Sand K-lll, K-IV & K-IX+X of J Field & Sand K-lll & K-IV of S Field, the
sources of water production are channeling or coning. Water breakthrough is also
observed in wells of AD Field particularly in sand K-IX and L Field in Sand Chhatral.
Hence at this stage for exploitation of such sand and for restricting the entry of
excessive water; Water Shut-off Job in producers and Profile Modification Job in
injectors is the only solution.
Since, 2011-12 to till date, Water Shut-off Job in 35 wells and Profile Modification Job
in 32 wells have been carried out in different fields of A Asset and total oil gain of
around 70 thousand m3 has been achieved till 1st January 2016. Total 8 PM Jobs and
7 WSO jobs have been carried out as on date during the current FY 2016-17. Out of
the fifteen jobs, six (1 PM +5 WSO) jobs in J field, one PM job in k field, one PM in W-
P, four PM Jobs in A field, one PM Job in ND field and one WSO job in L field have
been carried out in the A Asset. There is a wide scope of enhancing oil production
through this technique by attempting more wells, encouraged by the positive results
and based on detailed production performance analysis total number of 15 jobs (7
WSO & 8 PM) have been carried out during this year 2016-17.
2. Gel Optimisation
The chemical water shutoff methods extensively used since the last decade consist of
chemicals that are pumped into producers or injectors. Most of these systems are
based on polymeric solutions that after a, given time turn from low viscosity liquids to
strong or weak gels depending on their formulations. A polymer gel consists typically
of a water-soluble polymer and one or more cross-linking agents. The low viscosity
solution containing the polymer and the cross linkers, called gelant is converted into
the rubber-like gel structure through a cross-linking reaction in which polymer chains
are linked together to make a three-dimensional network.
It is essential to design the gel formulations (polymer, cross-linker type and their
depending on the operational and reservoir requirements. The gel properties such as
gelation time and gel strength are highly important to avoid early gelation and at the
same time, assure the appropriate placement in the reservoir. For designing the gel

43. 37
formulations in the present studies, polymer sample WS-106 obtained from A Asset
has been cross linked with hexamine and hydroquinone.
The Gelant formulation in alkaline solution, such as sodium hydroxide and sodium
chloride when subjected to elevated temperature, some of the amide group converts
to carboxylate group. Each of these carries negative charge. The proportion of amide
group is called the degree of hydrolysis and typically varies from 0 to 60%. In this form
polymer is called partially hydrolyzed polyacrylamide and its negatively charged
carboxylate group is susceptible to ionic cross-linking. The carboxylate group has very
high affinity for hydronium H30+ ions and so this gel has got a tendency to move
towards high water saturation and get solidified and in turn restrict the permeability of
the water in the reservoir. From the above studies the optimized gelant formulations
are;
Chemicals
For WSO Job For PM jobs
In ppm In
Percentage
(%)
In ppm In Percentage
(%)
WS-160 5000-
7000
0.5-0.7 6000-700 0.6-0.7
Hexamine 3000-
4000
0.3-0.4 3000-400 0.3-0.4
Hydroquinone 4000-
5000
0.4-0.5 4000-5000 0.4-0.5
Sodium
Chloride
10000 1.0 1000 1.0
3. Project Planning and Execution
A well selection procedure for a successful WSO/PM treatment is entirely based on
the analysis of reservoir rock, fluid properties and production injection history of the
field. The best candidates for WSO Job are chosen for their potential with estimated
remaining mobile hydrocarbons in place, productivity index (PI) values, numbers of
fracture intensity, completion types and water cut of the wells. The wells having high
PI values with high fracture density distributions located on the apex of the field are
the good candidates, Also the well having low cumulative oil recovery with high water
cut can also be a good candidate for WSO Job and finally application economics for
the selected wells are calculated.

44. 38
4. A Field
A field is situated 12 km. SE of A city in southern pan of the A- M tectonic block of C
Basin. Areal extent of the field is about 120 sq km. The field was discovered in 1965
with drilling of well A-01 and put on production in 1981 through well A-18 (K- IX+X). It
has multilayered silt/sandstone reservoirs in K formation. The pay zones encountered
in A fields are k-III, K-IV, K-V, K-VII, K-VIII, and K-IX & K-X. The pays K-III, K-IV & K-
V are gas bearing whereas K-VII, Vlll and K-IX+X are oil bearing. The pay zones K-IX
and X are the main reservoirs in the field with about 80% of the total OIIP. All the
reservoirs are producing under depletion drive, where pressure maintenance in K-
IX+X and partly in K-VII & K-VIII sands is done by water injection. Current liquid
production rate of this field is 286 m3/d & oil production rate is 176 m3/d with 46% WC
through 91 producers and cumulative production till 1st Jan 2016 is 1.71 MMt.
The water injection in A field is going on mainly in K-IX+X sand and partly in K-VIII
reservoirs. Water injection in K-IX+X sand was started in 1995 through A-20 and
subsequently more wells have been converted into water injector both in K-IX & X
sand. Though, the water injection started in 1995, but the large spacing between the
injectors and producers has resulted in delayed pressure response in the producers.
The maximum injection is being done in the central part of A field. Currently the water
is being injected in this field by 15 injectors with rate of 410 m3/d with average injection
pressure of approximately 88 ksc and cumulative water injection is
2953315 m3
till 1st
Dec 2016.
For better sweep efficiency of water flood system, profile modification job has been
recommended in A-108, A-121, A-127 and A-26. The tentative PM job plans of wells
A-108, A-121, A-26 & A-127 have been issued for field implementation and Job has
been executed in Well A- 127 in Oct 2016, A-121 in sept 2016, A-26 in Nov 2016
and A-108 in Nov 2016
Accomplished PM jobs
1. A-127, A-121
Production performance curves of the nearby producer wells A-90, A-122, A-119 were
plotted which indicates significant rise in the production of A-122 form Oct’16 whereas
water cut percentage in A-90 and A-119 has increased after the PM job therefore
further monitoring is required.

45. 39
Figure 20: Production Performance of the producer wells of A-127, A-121(injector wells) PM
Job done in Oct’16
2. A-108
Production performance of the nearby producer wells A-116 and A-106 indicates
significant rise in water cut percentage after Nov’16 therefore wells are under
monitoring to analysis the effect of the job done.
Figure 21: Production Performance of the producer wells of A-108(injector well)
PM Job done in Nov’16
0
20
40
60
80
100
120
0.00
5.00
10.00
15.00
20.00
25.00
Production Preformance of A-90
Ql(m3/d) Q0(m3/d) WC
0
5
10
15
20
25
30
35
0.00
1.00
2.00
3.00
4.00
5.00
Production Preformance of A-122
Ql(m3/d) Q0(m3/d) WC%
0
10
20
30
40
50
60
0.00
1.00
2.00
3.00
4.00
5.00
6.00
Production Preformance of A-119
Ql(m3/d) Q0(m3/d) WC
0
20
40
60
80
100
120
0.00
5.00
10.00
15.00
20.00
25.00
30.00
Production Prefomance of A-116
Ql(m3/d) Q0(m3/d) WC%
0
10
20
30
40
50
60
70
0.00
2.00
4.00
6.00
8.00
10.00
12.00
Production Prefomance of A-106
Ql(m3/d) Q0(m3/d) WC%

46. 40
3. A-26
Production performance of the producer well A-135 indicates decrease in the
water cut percentage and therefore increase in the productivity of the well.
Hence, PM job done in A-26 is a success.
Figure 22: Production Performance of the producer wells of A-26(injector well)
PM Job done in Nov’16
5. J Field
J field is located 50 km NW of A city. The field was discovered during 1965 when the
well S-9 (later renamed as J-01) produced oil and gas from a K pay. It has an aerial
extent of 30 sq. km and is on production since 1977. This asymmetrical anticline is
trending NW-SE and is plunging towards North-West. The field consists of three main
pay zones viz. K-lll, K-IV & K-IX+X which are operating under active water drive. It has
an OllP of 32.43 MMt with 17.72 MMt as ultimate recoverable reserves. The
cumulative oil production of J field as on 1st Dec 2016 is 16.356MMt, which is 48 % of
OllP. Analysis of the production graph of the field indicates declining trend after
achieving peak production in 1993. The oil production has decrease significantly and
Water cut percentage has also increased from about 48% in 1992 to a 86% in 2010.
Therefore, to increase oil production from the field, Water Shut-off job may be carried
out in high water cut wells as active aquifers in conjunction with adverse mobility of
crude has resulted in early coning to channeling. Although the recovery of this field is
high but still more reserves are left in the reservoir (current HC saturation is in
between40-45%). Based on the detailed analysis of production performance four WSO
jobs and one PM jobs were recommended viz. J-56, J-60, J-79, J-105 and J-98 were
recommended. Therefore, WSO job was executed in well J-56 during April’16, J-60
during June’16, J-79 and J-105 during Sept’16.
0
20
40
60
80
0.00
5.00
10.00
15.00
20.00
25.00
30.00
Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16
Production Prefomance of A-135
Ql(m3/d) Q0(m3/d) WC%

47. 41
Accomplished WSO jobs
Production performance plots of the wells indicate sudden decrease in the water cut
after the implementation of the jobs but the water cut seems to be increased
gradually after that. Therefore, wells are under monitoring to further study the
behavior of the reservoir.
Figure 23: Production Performance of the wells in which WSO Job was carried out
82
84
86
88
90
92
94
96
98
0
5
10
15
20
25
30
35
40
45
Production Preformance of J-56
Job Date 20-4-16
Qo(m3/d) Ql(m3/d) WC%
84
86
88
90
92
94
96
98
100
0
5
10
15
20
25
30
35
Production Preformance of J-79
Job Date 22-7-16
Qo(m3/d) Ql(m3/d) WC%
0
20
40
60
80
100
120
0
5
10
15
20
25
30
35
40
Production Preformance of J-105
Job Date 29-7-16
Qo(m3/d) Ql(m3/d) WC%
0
20
40
60
80
100
120
0
20
40
60
80
100
120
Production Preformance of J-60
Job Date 8-06-16
Qo(m3/d) Ql(m3/d) WC%

48. 42
Accomplished PM Jobs.
Profile Modification was implemented in the injector well J-98 and Production
performance curves of the nearby production wells viz. J-70, J-32, J-81, J-145, were
plotted which indicates that after profile modification there is a significant decline in
the percentage of water cut in some of the wells while other failed to show any effect,
which might be due to the variation of permeability in different section of the
reservoir. Therefore, further monitoring and analysis is required to enhance the
productivity of the well.
Figure 24: Production Performance curves of the producer wells of J-98(injector well)
PM Job done in May’16
0
20
40
60
80
100
0.000
0.500
1.000
1.500
2.000
2.500
3.000
3.500
Jan-16
Feb-16
Mar-16
Apr-16
May-16
Jun-16
Jul-16
Aug-16
Sep-16
Oct-16
Nov-16
Production Preformance
J-70(Injection well J-98)
Q0(m3/d) QL(m3/d) WC(v/v%)
86
88
90
92
94
96
98
0.000
0.500
1.000
1.500
2.000
2.500
Jan-16
Feb-16
Mar-16
Apr-16
May-16
Jun-16
Jul-16
Aug-16
Sep-16
Oct-16
Nov-16
Production Preformance
J-32(Injection well J-98)
Q0(m3/d) QL(m3/d) WC(v/v%)
0
10
20
30
40
50
60
70
0.000
0.050
0.100
0.150
0.200
0.250
0.300
0.350
Jan-16
Feb-16
Mar-16
Apr-16
May-16
Jun-16
Jul-16
Aug-16
Sep-16
Oct-16
Nov-16
Production Preformance
J-81(Injection well J-98)
Q0(m3/d) QL(m3/d) WC(v/v%)
0
20
40
60
80
100
0.000
0.200
0.400
0.600
0.800
1.000
1.200
1.400
1.600
Jan-16
Feb-16
Mar-16
Apr-16
May-16
Jun-16
Jul-16
Aug-16
Sep-16
Oct-16
Nov-16
Production Preformance
J-145(Injection well J-98)
Q0(m3/d) QL(m3/d) WC(v/v%)

49. 43
CHAPTER 6
Emulsion Formation Study
1. Introduction
To study how different chemical EOR methods acts on oil recovery, a small sample
experiment was conducted.
Different concentrations of each of the following chemicals were prepared-
a. Surfactant
b. Alkaline solution
c. Alkaline surfactant solution
d. Solvent (DGME and Xylene)
2. Theory
(phase behaviour study- an important evolution technique to optimise the alkali and
surfactant concentration and determination of solubilisation ratio and interpretation of
interfacial tension between oil and water.)
Phase behaviour study and interfacial tension measurement becomes an important
part in analysing the effectiveness of ASP flooding. Due to the darkness of the lower
phase, a direct measurement of IFT was not possible. Instead IFT can be inferred from
solubilisation ratios using Huh correlations:
mw=c/(Vw/Vs)2
mo=c/(Vo/Vs)2
where,
c is assumed to be 0.3 mN/m.
Vs = amount of synthetic surfactant in solution
Vw= difference between the aqueous phase initially present and final volume after
equilibration
Vo= difference between the initial oil present and the final volume of the excess oil
phase after equilibration
These correlations would work better if the solubilisation ratio includes the soap as
well as synthetic surfactant. A solubilisation ratio > 10 implies an IFT<3X10-3 mN/m.
Solubilisation ratios greater than 10 are observed in large range of alkali and surfactant
concentrations, where we expect to have ultra-low surface tension.

50. 44
3. Observations
1. Surfactant
Surfactant
conc.
Oil column
at present
(in ml)
Water
remaining
(in ml)
Vw / Vs Vo / Vs mw
(mN/m)
mo
(mN/m)
500ppm (5 ml
oil+ 5 ml
surf.)
5.5 4.5 200 200 0.75x10-5 0.75x10-5
1000ppm (5
ml+ 5 ml
surf.)
6.3 3.7 260 260 0.44x10-5 0.44x10-5
1500ppm (5
ml+ 5 ml
surf.)
7 3 266.66 266.66 0.42x10-5 0.42x10-5
2000ppm (5
ml+ 5 ml
surf.)
8 2 300 300 0.33x10-5 0.33x10-5
2500ppm (5
ml+ 5 ml
surf.)
8 2 240 240 0.52x10-5 0.52x10-5
3000ppm (5
ml+ 5 ml
surf.)
8.1 1.9 206.66 206.66 0.70x10-5 0.70x10-5
2. Alkali.
Alkali conc.. Oil column
at present
(in ml)
Water
remaining
(in ml)
Vw / Vs Vo / Vs mw
(mN/m)
mo
(mN/m)
500 ppm (5ml
alkali+ 5 ml
crude)
7.9 2.1 1160 1160 0.022x10-5
0.022x10-5
1000 ppm (5ml
alkali+ 5 ml
crude)
8.0 2.0 600 600 0.083 x10-5
0.083 x10-5
1500ppm (5ml
alkali+ 5 ml
crude)
8.1 1.9 413.33 413.33 0.17 x10-5
0.17 x10-5
2000ppm (5ml
alkali+ 5 ml
crude)
8.2 1.8 320 320 0.29 x10-5
0.29 x10-5
2500ppm (5ml
alkali+ 5 ml
crude)
7.7 2.3 216 216 0.643 x10-5
0.643 x10-5
3000ppm
(5ml alkali+ 5
ml crude)
7.5 2.5 166.66 166.66 1.08 x10-5 1.08 x10-5

51. 45
3. Alkali Surfactant (prepared by mixing 2% alkali solution with 2500 ppm
surfactant)
Alkali+
surfactant
Oil at
present
Water
remaining
5 ml Alk.
Surf+ 5 ml oil
8.8 1.2
6 ml Alk.
Surf+ 5 ml oil
7.5 2.5
7 ml Alk.
Surf+ 5 ml oil
3.5 6.5
8 ml Alk.
Surf+ 5 ml oil
2.5 7.5
4. Solvent
Solvent Oil column at
present (ml)
Water remaning (ml)
Xylene+Crude+Water+
(4ml+5ml+1ml)
6.6 3.4
Xylene+
DGME+Water+Crude
(2ml+2ml+1ml+5ml)
7 3
DGME+crude+water
(4ml+5ml+1ml)
5.5 4.5
4. Results
1. Surfactant- We can see that 2000ppm or 2500ppm surfactant works best by
forming an extra of volume 8-5 = 3 ml hence and only 2 ml of water is remaining.
2. Alkali- We can see that for alkali solution, 2000ppm or 2% alkali solution is best
for effective oil emulsion formation as it is forming an extra oil volume of 8.2-5
= 3.2 ml while only 1.8 ml of water is remaining.
3. Alkali Surfactant- An alkali concentration of 2 % mixed with 2500ppm of
surfactant concentration when used in 1:1 ratio with oil works best as it forms
an extra 3.8 ml crude oil.
4. Solvent- Solvent has no effect on reducing the oil water interfacial tension.
However, it can reduce the pour point of crude oil as well as helps in facilitating
the flow of crude oil. Therefore, solvent shouldn’t be use for oil recovery
processes. It should be rather used in wax deposition problems.

52. 46
Figure 25: Surfactant solution added to oil Figure 26: Alkali solution added to oil
Figure 27: Alkali surfactant solution added to oil in different concentration
Figure 28: Comparison of Surfactant, Alkali, Alkali-Surfactant and Solvents

53. 47
CHAPTER 7
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