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Various Enhanced Oil Recovery methods are explained briefly and Microbial Enhanced Oil recovery is discussed as the latest development in EOR Technique.
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Dissertation submitted in partial fulfilment of the requirement
for the B.Tech degree in Petroleum Engineering
By:
Animesh Jain 10BPE083
Harsh Shah 10BPE115
Kuldip Patel 10BPE206
Neema Agarwal 10BPE072
Pradeepika Chanana 10BPE197
Prashant Thawrani 10BPE234
Reila Chakraborty 10BPE009
Shamit Rathi 10BPE066
Ujjwal Kumar 10BPE103
2010-2014
School of Petroleum Technology,
Pandit Deendayal Petroleum University,
Raisan, Gandhinagar
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Innovation in EOR techniques Page | 1
Acknowledgements The work of our B.Tech project titled “Innovation in EOR Techniques in Cambay Region” has
been a persistent endeavour from a lot of people and so we would like to thank all of them
for their support and guidance throughout the session.
First of all, we would like to thank Dr. Bijay K Behera, internal mentor of the project, who
guided the group throughout the project work and helped with the relevant data required
for the project. His guidance helped us to carry out the work smoothly and efficiently.
We also wish to thank Mr. R.K. Vij, GM-ONGC, external mentor for the project, for providing
us with technical assistance and valuable insights into the concepts of EOR.
Thanking all,
Animesh Jain 10BPE083
Harsh Shah 10BPE115
Kuldip Patel 10BPE206
Neema Agarwal 10BPE072
Pradeepika Chanana 10BPE197
Prashant Thawrani 10BPE234
Reila Chakraborty 10BPE009
Shamit Rathi 10BPE066
Ujjwal Kumar 10BPE103
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Innovation in EOR techniques Page | 2
Table of Contents
Introduction ........................................................................................................................ 6
Oil Recovery ........................................................................................................................ 7
Primary recovery ......................................................................................................... 7
Secondary recovery ..................................................................................................... 7
Tertiary recovery (EOR) ............................................................................................... 7
IOR vs. EOR .................................................................................................................. 8
Enhanced Oil Recovery Techniques .................................................................................... 9
Gas Injection ................................................................................................................ 9
Miscible Gas Injection .......................................................................................... 9
Immiscible Gas Injection ...................................................................................... 9
Chemical Flooding ..................................................................................................... 10
Alkaline Flooding – Wettability Alteration ......................................................... 10
Micellar/Polymer Flooding ................................................................................ 12
Alkali, Surfactant, Polymer Flooding .................................................................. 13
Thermal Recovery Processes ..................................................................................... 14
Cyclic Steam Injection (Steam Stimulation, Steam Soak or Huff and Puff): ...... 14
Steam Flooding (Steam drive, Continuous Steam Injection): ............................ 15
In-Situ Combustion (Fire-flood): ........................................................................ 16
Microbial Enhanced Oil Recovery ............................................................................. 17
Huff and Puff Method ........................................................................................ 18
Microbial Flooding ............................................................................................. 19
Economics of the MEOR stimulation: ................................................................ 19
Advantages of MEOR: ........................................................................................ 19
Disadvantages of MEOR: .................................................................................... 19
Screening criteria .............................................................................................................. 20
Geology of the Cambay Basin ........................................................................................... 22
Geographic Location of the basin ............................................................................. 22
Tectonic history ......................................................................................................... 22
Evolution of Basin ...................................................................................................... 23
Generalized Stratigraphy ........................................................................................... 24
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Petroleum System ..................................................................................................... 26
Thermal History ......................................................................................................... 26
Source Potential ........................................................................................................ 27
Petroleum plays......................................................................................................... 28
Case Study I: Enhanced Oil Recovery by In-Situ Combustion (ISC) Technique in Balol and
Santhal Fields, Mehsana .......................................................................................................... 29
Background ................................................................................................................ 29
Geology ..................................................................................................................... 29
Reservoir & fluid properties ...................................................................................... 30
ISC implementation ................................................................................................... 30
ISC process................................................................................................................. 30
Production performance ........................................................................................... 31
Issues ......................................................................................................................... 32
Case Study II: Enhanced Oil Recovery by Alkaline Surfactant Flooding (ASP) Technique in
Jhalora Field ............................................................................................................................. 33
Reservoir Characteristics ........................................................................................... 33
Field Implementation ................................................................................................ 35
Production Performance of ASP pilot producers ...................................................... 35
Conclusion and Further Plan ..................................................................................... 36
Case Study III: Enhanced Oil Recovery by Polymer Flooding Technique in Sanand Field 37
Background ................................................................................................................ 37
General Geology ........................................................................................................ 37
Reservoir and Fluid properties .................................................................................. 37
Field Implementation of Polymer EOR Technique .................................................... 38
Performance Monitoring ........................................................................................... 39
Production Performance ........................................................................................... 39
Field Review .............................................................................................................. 40
Case Study III: Enhanced Oil Recovery by Alkaline Surfactant Technique in Viraj Field .. 41
Field history ............................................................................................................... 41
Reservoir Description ................................................................................................ 41
Field implementation: ............................................................................................... 43
Data Acquisition ........................................................................................................ 43
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Results ....................................................................................................................... 44
Conclusion ................................................................................................................. 44
Economic analysis of EOR projects ................................................................................... 45
Identification of major costs ...................................................................................... 45
Evaluating the NPV and ROR for an EOR project ....................................................... 46
EOR Project Risks ....................................................................................................... 48
Major Economic Models used ................................................................................... 49
EOR Economic Model: ............................................................................................... 50
Appendix ........................................................................................................................... 51
References ........................................................................................................................ 53
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List of Figures
FIGURE 1 OIL RECOVERY CLASSIFICATIONS (LAKE, 1989) ......................................................................... 7
FIGURE 2 EFFECT OF FLOOD WATER SALINITY ON RECOVERY OF SYNTHETIC ACIDIC OIL BY ALKALINE
WATERFLOODING (C.E.COOKE, 1974) ........................................................................................ 11
FIGURE 3 SCHEMATIC ILLUSTRATION OF POLYMER FLOODING SEQUENCE (DRAWING BY JOE LINDLEY, U.S.
DEPARTMENT OF ENERGY, BARTLESVILLE, OKLA.) (LAKE, 1989) ...................................................... 12
FIGURE 4 RESIDUAL OIL UNDER SEM (POLYMER FLOODING AND ASP FLOODING IN DAQING OILFIELD) ......... 13
FIGURE 5 STEAM INJECTION PROCESS (NIPER, OKLAHOMA) .................................................................. 14
FIGURE 6 STEAM FLOOD DISPLACING OIL FROM RESERVOIR (E&P MAGAZINE, AUG 29, 2007) .................... 15
FIGURE 7 IN-SITU COMBUSTION PROCESS (NIPER, OKLAHOMA) ............................................................ 16
FIGURE 8 HUFF AND PUFF METHOD (M. M. SCHUMCHER, 1980): .................................................... 18
FIGURE 9 MICROBIAL FLOODING (M. M. SCHUMCHER, 1980) .......................................................... 19
FIGURE 10 GEOGRAPHY OF THE CAMBAY BASIN (DGH) .......................................................................... 22
FIGURE 11 SCHEMATIC OF TECTONIC BLOCKS OF CAMBAY RIFT BASIN SEPERATED BY TRANSFER FAULTS (MADAN
MOHAN, 1995) ..................................................................................................................... 22
FIGURE 12 GEOLOGICAL CROSS SECTION ALONG CAMBAY RIFT BASIN (MADAN MOHAN, 1995) .................. 23
FIGURE 13 GENERALIZED STRATIGRAPHY OF THE CAMBAY BASIN ............................................................ 25
FIGURE 14 TOTAL ORGANIC CARBON (TOC) CONTOUR IN CAMBAY SHALE ............................................... 27
FIGURE 15 BALOL AND SANTHAL FIELDS IN CAMBAY BASIN (G.K PANCHANAN, 2006) ............................... 29
FIGURE 16 CROSS PLOT OF AIR RATE & OIL PRODUCTION RATE IN PHASE I (HAR SHARAD DAYAL ET.AL, 2010) 31
FIGURE 17 CROSS PLOT OF AIR RATE & OIL PRODUCTION RATE IN PHASE II (HAR SHARAD DAYAL
ET.AL, 2010). ...................................................................................................................... 31
FIGURE 18 TECTONIC MAP OF CAMBAY BASIN (DEBASHIS ET AL., 2008) .................................................. 33
FIGURE 19 SCHEMATIC MAP OF JHALORA ASP PILOT AREA (JAIN, DHAWAN, & MISHRA, 2012) ................. 35
FIGURE 20 COMBINED PERFORMANCE OF SIX JHALORA ASP PILOT PRODUCERS (JAIN, DHAWAN, & MISHRA,
2012).................................................................................................................................. 36
FIGURE 21 LOCATION MAP OF SANAND FIELD (CHANCHAL DASS, 2008). ............................................... 37
FIGURE 22 PILOT WELLS AND EXPANDED PILOT PHASE WELLS (MAHENDRA PRATAP, 1997). ....................... 38
FIGURE 23 WELLS IN COMMERCIALISATION AREA (MAHENDRA PRATAP, 1997). ...................................... 38
FIGURE 24 PERFORMANCE OF EXPANDED POLYMER PILOT (MAHENDRA PRATAP, 1997). ........................... 39
FIGURE 25 PERFORMANCE OF SANAND POLYMER FLOOD PROJECT (CHANCHAL DASS, 2008). .................... 40
FIGURE 26 ASP PILOT LOCATION IN VIRAJ FIELD ................................................................................. 41
FIGURE 27 JJ TABER EOR SCREENING CRITERIA .................................................................................. 51
List Of Tables
TABLE 1 BIO-PRODUCTS AND THEIR APPLICATIONS TO ENHANCED OIL RECOVERY (JANSHEKAR, 1985): .......... 17
TABLE 2 RESERVOIR PARAMETERS OF JHALORA K-IV SAND (JAIN, DHAWAN, & MISHRA, 2012) ................... 34
TABLE 3 RESERVOIR DESCRIPTION OF VIRAJ FIELD: ............................................................................... 42
TABLE 4 CRUDE OIL PROPERTIES IN VIRAJ: ......................................................................................... 42
TABLE 5 CHARACTERISTICS OF SURFACTANT USED IN VIRAJ: ................................................................... 42
TABLE 6 PARAMETERS MONITORED DURING IMPLEMENTATION: ............................................................ 43
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Introduction
In today’s time, Enhanced Oil Recovery (EOR) has become one of the sought after research
arenas in the oil and gas industry. The industry average of 35% recovery efficiency for
conventional crude oil results in a large amount of identified oil left behind, despite existing
production infrastructure. Many EOR techniques are already in practice around the world
but the global energy demands are ever-increasing. This propels innovations in the existing
EOR schemes as even a meagre increase in production of oil is highly valued in the industry.
This project deals with developing an economically feasible innovation in any existing EOR
scheme for the petroliferous basin in Gujarat i.e. the Cambay Basin. The focus is on major
fields in the Cambay Basin, namely Balol & Santhal, Viraj, Sanand & Jhalora. This report
entails a detailed study of the fields and the current EOR schemes in use. An innovation in
EOR technique can only be designed with proper background knowledge of the ongoing
process and its limitations.
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Oil Recovery There are three phases of recovering as below and in figure 1:
FIGURE 1 OIL RECOVERY CLASSIFICATIONS (LAKE, 1989)
Primary recovery Primary Recovery Mechanism occurs when wells produce because of natural energy from
expansion of gas and water within the producing formation, which pushes fluids into the
well bore and lifts them to the surface.
Secondary recovery It occurs as artificial energy is applied to inject fluids into the well bore and lift fluids to the
well bore. This may be accomplished by injecting gas down a hole, installing a subsurface
pump, or injecting gas or water into the formation itself. Secondary recovery is done when
well, reservoir, facility, and economic conditions permit.
Tertiary recovery (EOR) EOR occurs when means of increasing fluid mobility within the reservoir are introduced in
addition to secondary techniques. This may be accomplished by introducing additional heat
into the formation to lower the viscosity (thin the oil) and improve its ability to flow to the
well bore. Heat may be introduced by either injecting steam in a steam flood or injecting
oxygen to enable the ignition and combustion of oil within the reservoir in a fire flood.
(Speight, 2009)
During primary recovery, the natural pressure of the reservoir or gravity drive oil into the
well bore, and artificial lift techniques (such as pumps) bring the oil to the surface. Natural
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energy sources include solution gas drive, gas cap drive, natural water drive, fluid and rock
expansion, and gravity drainage. Typically, only about 10% of a reservoir’s original oil in place
is produced during this phase.
Secondary recovery techniques added to the field’s productive life, generally injecting water
or gas to displace oil and drive it to a production well bore, result in the recovery of an
additional 20-40% of the original oil in place. In this phase, reservoir’s natural energy is
augmented through injection. Gas injection, is either into a gas cap for pressure
maintenance and gas cap expansion or into oil-column wells to displace oil immiscibly
according to relative permeability and volumetric sweep out considerations. Gas processes
based on other mechanisms such as oil swelling, oil viscosity reduction, or favourable phase
behaviour, are considered as EOR processes.
Tertiary oil recovery methods take oil recovery one step further and rely on methods that
reduce viscosity of the oil and increase oil mobility, compared to the natural- or induced-
energy methods of primary and secondary recovery. It is started before secondary recovery
techniques are no longer enough to sustain production. For example, thermal EOR methods
are recovery methods in which the oil is heated to make it easier to extract; usually steam is
used for heating the oil. In chemical EOR, the injected fluids interact with the reservoir
rocks/oil system to create condition favourable for oil recovery. These interactions might
result in lower IFT’s, oil swelling, oil viscosity reduction, wettability modification or
favourable phase behaviour. (Don W. Green, 1998)
IOR vs. EOR
EOR is a broader idea that refers to the injection of fluids or energy not normally present in
an oil reservoir to improve oil recovery that can be applied at any phase of oil recovery
including primary, secondary, and tertiary recovery. Thus EOR can be implemented as a
tertiary process if it follows a waterflooding or an immiscible gas injection, or it may be a
secondary process if it follows primary recovery directly. Nevertheless, many EOR recovery
applications are implemented after waterflooding. The term Improved Oil Recovery (IOR)
techniques refers to the application of any EOR operation or any other advanced oil-
recovery technique that is implemented during any type of ongoing oil recovery process.
Examples of IOR applications are any conformance improvement technique that is applied
during any type of ongoing oil recovery operations. Other examples of IOR applications are:
hydraulic fracturing, scale-inhibition treatments, acid-stimulation procedures, infill drilling,
and the use of horizontal wells. (Romero-Zerón)
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Enhanced Oil Recovery Techniques
Gas Injection Gas processes target the light and medium gravity crude oils by lowering the interfacial
tension between the injected fluid and the crude oil to minimize the trapping of oil in the
rock pores by capillary or surface forces.
The important strategy related questions in the design of gas injection projects are:
Should it be a completely miscible (on first contact or multiple contacts) or near-miscible or immiscible project?
How should the mobility of the displacement be controlled? Does the injection of a miscible solvent affect reservoir wettability? If so, how can it
be accounted for in the design? What are the effects of reservoir wettability on waterflood and miscible flood
performance? What are the effects of rock heterogeneity on displacement mechanisms and
miscible flood performance? What are the effects of changing reservoir pressure on minimum miscibility pressure,
and injected solvent gas composition? How do we determine miscibility?
Miscible Gas Injection Oil recoveries for gas injection processes are usually greatest when the process is
operated under conditions where the gas can become miscible with the reservoir oil. The
primary objective of miscible gas injection is to improve local displacement efficiency
and reduce residual oil saturation below the levels typically obtained by water flooding.
Examples of miscible gas injectant are CO2 or N2 at sufficiently high pressure, dry gas
enriched with sufficient quantities of LPG components, and sour or acid gases containing
H2S. The conditions under which gas becomes miscible with oil (MMP) are most
commonly determined in the laboratory using slim-tube experiments. Phase behavior
measurements, in combination with compositional simulation, can also be used to
determine miscibility conditions. (G.F. Teletzke, 2005)
Immiscible Gas Injection The key to successful gas flooding is to contact as much of the reservoir with the gas as
possible and to recover all of the oil once contacted. Injected gases must be designed to
be miscible with the oil so that oil previously trapped by capillary forces is transferred
into a more mobile phase that flows easily to the production well. Flow is ideally piston-
like in that whatever gas volume is injected displaces an approximately equal volume of
reservoir fluid. Unfortunately, miscibility is not always possible and reservoir
heterogeneities can cause gas to cycle through one or more layers, which results in poor
recovery efficiency. A proper gas flood design will consider both the displacement and
sweep efficiency that result and the profitability of that process. (Johns, 2013)
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Chemical Flooding Chemical enhanced oil recovery (EOR) includes processes in which chemicals are injected to
improve oil recovery. The primary goal is to recover more oil or to improve the sweep
efficiency of the injected fluid by either one or a combination of the following processes:
(1) Mobility control by adding polymers to reduce the mobility of the injected water, and
(2) Interfacial tension (IFT) reduction by using surfactants, and/or alkalis.
Chemical EOR faces significant challenges, especially in light oil reservoirs. One of the
reasons is the availability, or lack of, compatible chemicals in high temperature and high
salinity environments.
There are three general methods in chemical flooding technology.
Alkaline Flooding Micellar/Polymer Flooding Alkali, Surfactant, Polymer(ASP) Flooding
Alkaline Flooding – Wettability Alteration In this method, the change in wettability characteristics is responsible for improved recovery
and is particularly recommended for reservoir crudes containing organic acids such as
naphthenic acids. The organic acids occurring naturally in some of the crude oils react with
the alkaline water to produce soaps at the oil/water interface. The soaps thus formed lower
the interfacial tension between the crude oil and the flood water by a factor of several
hundred. Under appropriate conditions of salinity, pH and temperature, the wettability of
the porous media becomes more favourable to enhanced production. The matrix material
wettability is always changed from strongly water-wet to preferentially oil-wet as the flood
front passed a point which is caused by adsorption of soap molecules (formed by the
interracial reaction) onto the solid surface. (C.E. Cooke, Jr. et al.) When the proper alkaline
water and acidic oils flow through the porous media, an oil-water emulsion is formed. The
flow properties of this type of emulsion generate a highly non-uniform pressure gradient
near the emulsion front. This pressure gradient is capable of overriding the capillary forces
and effectively displaces the oil from the pores.
The various mechanisms active at the front where the alkaline water displaces the crude oil
are:
A drastic reduction of oil/water interfacial tension; Wetting of the porous media; Formation of water drops within the oil phase; Drainage of oil from the volume between the alkaline water drops to produce an
emulsion containing very little oil.
The compatibility of a given alkali is of utmost importance. The reaction of the alkali with the
high molecular weight acids is required for altering the wettability. Acidic gases, such as H2S
and CO2, are tolerable only at lower concentrations, because their reaction products (Na2S
and Na2CO3) with excess NaOH may still be sufficiently alkaline. Bivalent ions present in
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water could deplete an alkali slug by the formation of insoluble hydroxides. This can be
avoided by placing a fresh water or sodium chloride buffer before injecting the alkali.
Gypsum or anhydrides present in substantial quantities would render a slug ineffective due
to the dissolution of CaSO4 and the precipitation of calcium hydroxide. Clays with high-ion-
exchange capabilities would also render the sodium hydroxide slug ineffective by exchanging
hydrogen for sodium. (Narendra Gangoli, 1977)
When oil containing organic acids is flooded with alkaline water, the result can be a high oil
recovery efficiency, provided a bank of viscous oil-in-water emulsion forms in situ. The
amount of additional oil recovered depends on the pH and salinity of the water and the type
and amount of organic acid it contains, as well as on the amount of fines in the porous
medium. (C.E.Cooke, 1974)
FIGURE 2 EFFECT OF FLOOD WATER SALINITY ON RECOVERY OF SYNTHETIC ACIDIC OIL BY ALKALINE WATERFLOODING
(C.E.COOKE, 1974)
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Micellar/Polymer Flooding Micellar-polymer flooding is based on the injection of a chemical mixture that contains the
following components: water, surfactant, co-surfactant (which may be an alcohol or another
surfactant), electrolytes (salts), and possible a hydrocarbon (oil). Micellar-polymer flooding is
also known as Micellar, micro emulsion, surfactant, low-tension, soluble-oil, and chemical
flooding. The differences are in the chemical composition and the volume of the primary
slug injected. For instance, for a high surfactant concentration system, the size of the slug is
often 5%-15% pore volumes (PV), and for low surfactant concentrations, the slug size ranges
from 15%-50% PV. The surfactant slug is followed by polymer-thickened water. The
concentration of polymer ranges from 500 mg/L to 2,000 mg/L. The volume of the polymer
solution injected may be 50% PV, depending on the process design. Some of the main
surfactant requirements for a successful displacement process are as follows:
The injected surfactant slug must achieve ultralow IFT (IFT in the range of 0.001 to 0.01
mN/m) to mobilize residual oil and create an oil bank where both oil and water flows as
continuous phases.
It must maintain ultralow IFT at the moving displacement front to prevent mobilized oil from
being trapped by capillary forces.
Long-term surfactant stability at reservoir conditions (temperature, brine salinity and
hardness). (Romero-Zerón)
FIGURE 3 SCHEMATIC ILLUSTRATION OF POLYMER FLOODING SEQUENCE (DRAWING BY JOE LINDLEY, U.S. DEPARTMENT OF
ENERGY, BARTLESVILLE, OKLA.) (LAKE, 1989)
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Alkali, Surfactant, Polymer Flooding In the Alkaline Surfactant Polymer (ASP) process, a very low concentration of the surfactant
is used to achieve ultra-low interfacial tension between the trapped oil and the injection
fluid/formation water. The ultra-low interfacial tension also allows the alkali present in the
injection fluid to penetrate deeply into the formation and contact the trapped oil globules.
The alkali then reacts with the acidic components in the crude oil to form additional
surfactant in-situ, thus, continuously providing ultra-low interfacial tension and freeing the
trapped oil. In the ASP Process, polymer is used to increase the viscosity of the injection
fluid, to minimize channelling, and provide mobility control. ASP flooding combines
interfacial tension-reducing chemicals (alkali and surfactant) with a mobility control chemical
(polymer). Alkali and surfactant both minimize capillary forces that trap waterflood residual
oil, while the polymer improves reservoir contact and flood efficiency. (Khaled Abdalla
Elraies, 2012)
FIGURE 4 RESIDUAL OIL UNDER SEM (POLYMER FLOODING AND ASP FLOODING IN DAQING OILFIELD)
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Thermal Recovery Processes Thermal recovery pertains to oil recovery processes in which heat plays a principal role.
Thermal EOR methods are generally applicable to heavy, viscous crudes. Thermal enhanced
oil recovery techniques are generally applied to relatively shallow (less than 3,000 feet) very
viscous heavy oil (generally defined as oil with API gravity between 10 and 20 degrees).
Heavy oil typically has a viscosity between 100 and 10,000 cP and does not flow unless
diluted with a solvent or heated. Heat is applied to the crude to:
reduce the viscosity of the crude, activate a solution gas drive in some instances, result in thermal expansion of the oil and hence increased relative permeability, Create distillation and, in some cases, thermal cracking of the oil. (Kok, 2008)
Thermal methods are generally of three types:
Cyclic Steam Injection (Steam Stimulation, Steam Soak or Huff and Puff): In this process, steam is injected down a producing well to heat up the area around the well bore and increase recovery of the oil immediately adjacent to the well. After injection of short period, the well is placed back on production. This is essentially a well bore stimulation technique, each well responding independently. (Kok, 2008)
FIGURE 5 STEAM INJECTION PROCESS (NIPER, OKLAHOMA)
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Steam Flooding (Steam drive, Continuous Steam Injection): The steam flooding involves the continuous injection of about 80% quality steam into
reservoir to transfer heart to oil bearing formation, which reduces oil viscosity and
increases the mobility ratio of oil and displaces crude towards producing wells. (Abdus
Satter, 1994)
Steam recovers crude by:
Heating the crude oil and reducing the viscosity. Thermal expansion of oil and steam distillation. Supplying pressure to drive oil to producing well.
FIGURE 6 STEAM FLOOD DISPLACING OIL FROM RESERVOIR (E&P MAGAZINE, AUG 29, 2007)
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In-Situ Combustion (Fire-flood): This process involves starting a fire in the reservoir and injecting air to sustain the burning of
some of the crude oil. The heat generated will increase the temperature of crude oil which
in turn will decrease the viscosity of the crude oil and help the fluid to flow more readily
from the formation into the production well. Another phenomenon, thermal and catalytic
cracking, that occurs during this process helps in up gradation of crude oil. (Abdus Satter,
1994)
FIGURE 7 IN-SITU COMBUSTION PROCESS (NIPER, OKLAHOMA)
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Microbial Enhanced Oil Recovery Microbial Enhanced Oil Recovery (MEOR) is a biological based technology consisting in
manipulating function or structure, or both, of microbial environments existing in oil
reservoirs. MEOR is a tertiary oil extraction technology allowing the partial recovery of the
commonly residual two-thirds of oil (Sen, 2008) thus increasing the life of mature oil
reservoirs.
MEOR relies on microbes to ferment hydrocarbons and produce by-products such as bio
surfactants, Alcohols and carbon dioxide which lead to Reduction of Interfacial tension,
Selective plugging of the most permeable zones and Reduction of oil viscosity. Bacterial
growth occurs at exponential rate; therefore bio surfactants are rapidly produced. The
activity of bio surfactants compare favourably with the activity of chemically synthesized
surfactants. MEOR stimulation can be chemically promoted by injecting electron acceptors
such as nitrate; easy fermentable molasses, vitamins or surfactants. Alternatively, MEOR is
promoted by injecting exogenous microbes, which may be adapted to oil reservoir
conditions and be capable of producing desired MEOR agents.
As a result, part of the immobilized oil can be remobilized, and zones upswept earlier can be
involved in oil displacement. There are two ways of using microbial processes:
Microbial production of desired product at the surface and the subsequent injection into a reservoir;
Direct injection of microorganism into a reservoir and in-situ generation of desirable product.
TABLE 1 BIO-PRODUCTS AND THEIR APPLICATIONS TO ENHANCED OIL RECOVERY (JANSHEKAR, 1985):
Bio-product Effects Acids Modification of reservoir rock
Improvement of porosity and permeability
Reaction with calcareous rocks & CO2 production
Biomass Selective or non-selective plugging
Emulsification through adherence to hydrocarbons
Modification of solid surfaces
Degradation & alteration of oil
Reduction of oil viscosity and oil pour point
Desulfurization of oil
Gases Reservoir re pressurization
Oil swelling
Viscosity reduction
Increase of permeability due to solubilisation of carbonate rocks by CO2
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Solvents Dissolving of oil
Surface-active
Agents
Lowering of interfacial tension
Emulsification
Polymers Mobility control
Selective plugging
MEOR stimulation can be carried out by two methods
Huff and Puff Method In huff and puff method water, nutrients and microbes injected and then well shut-in
and give time to microbes to grow. During their growth, they use nutrients and
produce surfactant, polymer, alcohols and CO2. Then production can be started from
same well. While in Microbial Flooding the nutrients and microorganisms are
injected from injection well and production is obtained from production well.
FIGURE 8 HUFF AND PUFF METHOD (M. M. SCHUMCHER, 1980):
Schematic showing the migration of cells and the
synthesis of metabolic products around the wellbore
following inoculation and closing of injection well
(Huff stage)
Schematic showing the production of oil at the end of
the incubation period, when the well is reopened (Puff
stage)
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Microbial Flooding
FIGURE 9 MICROBIAL FLOODING (M. M. SCHUMCHER, 1980)
Economics of the MEOR stimulation: Microbes and nutrients are relatively cheap materials. Cost is independent of oil prices. Implementation needs minor modifications to field facilities. Economically attractive for marginal producing wells. The total cost of incremental oil production from MEOR is only 2 – 3 $/bbl.
Advantages of MEOR: Easy application. Low energy input requirement for microbes to produce MEOR agents. More efficient than other EOR methods when applied to carbonate oil reservoirs. Microbial activity increases with microbial growth. This is opposite to the case of
other EOR additives in time and distance. Cellular products are biodegradable and therefore can be
considered environmentally friendly.
Disadvantages of MEOR: The oxygen deployed in aerobic MEOR can act as corrosive agent on non-resistant
topside equipment and down-hole piping Anaerobic MEOR requires large amounts of sugar limiting its applicability in offshore
platforms due to logistical problems Exogenous microbes require facilities for their cultivation. Indigenous microbes need a standardized framework for evaluating microbial
activity, e.g. specialized coring and sampling techniques.
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Screening criteria
Success of a particular EOR project depends on a large number of variables that are
associated with a given oil reservoir, for instance, pressure and temperature, crude oil type
and viscosity, and the nature of the rock matrix and connate water. Not every type of EOR
process can be applied to every reservoir. The choice of which EOR method to apply to a
particular reservoir thus, becomes challenging. It is best done based on a detailed study of
each specific field. Evaluation is carried out at each stage to increase the chances of an EOR
technique achieving technical and economic success. (Terry, 2001)
The application of EOR processes are both reservoir-specific and reservoir fluid-specific. This
literally means that each EOR process must be specifically evaluated before it can be applied
to a reservoir. The evaluation process is typically extensive and may include laboratory work,
geologic and reservoir modeling, economic analyses, and in many cases field trial in the form
of a pilot test. The different selection criteria presented are meant to serve as the first-pass
screening procedures that compare the candidate reservoir with other reservoirs that have
been produced with an EOR process. They cannot replace the rigorous evaluation procedure
that each EOR process must undergo before it is actually implemented in the field.
The first step in the evaluation procedure is to gather as much data about the reservoir as
possible. The data set can be used to match with the screening criteria for various recovery
methods. These criteria are usually based on the past field successes and failures to provide
a positive match for an EOR technique.
Once the possible number of feasible EOR techniques which could be applied has been
narrowed, the next step in the procedure is laboratory analysis. Physical properties of the
fluids and combinations of fluids, including that of crude oil and formation water needs to be
studied for the chosen technique. After the field history is evaluated, updated static and
dynamic reservoir models can be developed for analyzing the EOR potential of the reservoir.
The task of screening an EOR method has become easier and more efficient because of the
increase in the no. of iterations that can be done. A number of models, correlations and
computer models are available in the market for this purpose.
Operators compare expected supply costs and project economics to the scenario when the
production is continued without any EOR technique. When a field has more than one
reservoir, each reservoir should be evaluated individually by a screening guide, and a
complete study of the reservoir should be performed. If the simulation study indicates that
the project is meeting company’s technical and financial requirements, then it can be
applied to the field.
These screening criteria (attached in Appendix) are only guidelines. If a particular reservoir–
crude oil application appears to be on a borderline between two different processes, it may
be necessary to consider both processes. Once the number of processes has been reduced
to one or two, a detailed economic analysis will have to be conducted.
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Taber et al. (1976) came up with a set of screening criteria that should guide petroleum
engineers on the particular choice of EOR method to use. Since then, a no. of screening
criteria have been proposed by different authors, as a result of analyzing fields in which
particular methods have been applied and found successful.
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Geology of the Cambay Basin
Geographic Location of the basin The Cambay rift Basin, a rich Petroleum Province of
India, is a narrow, elongated rift graben, extending
from Surat in the south to Sanchor in the north. In
the north, the basin narrows, but tectonically
continues beyond Sanchor to pass into the Barmer
Basin of Rajasthan. On the southern side, the basin
merges with the Bombay Offshore Basin in the
Arabian Sea. Basin is roughly limited by latitudes 21˚
00' and 25˚ 00' N and longitudes 71˚ 30' and 73˚ 30' E.
The total area of the basin is about 53,500 sq. km. (DGH)
Tectonic history The Cambay Basin rifting took place around 65 Ma,
concomitant with the eruption of Deccan volcano
during rift-drift transition phase of the Indian plate.
The rift initiation is characterized by basin bounding
extensional fault (listric / planar normal fault)
facilitating the initial basin subsidence with the up-
liftment of the basin margin of rift shoulders. The
basin is divided into different tectonic blocks linked
with each other by transfer fault system (figure 11).
The five tectonic blocks in the basin are:
1. Sanchor–Patan 2. Mehsana–Ahmedabad 3. Tarapur–Cambay 4. Jambusar–Broach 5. Narmada – Tapti
FIGURE 10 GEOGRAPHY OF THE CAMBAY
BASIN (DGH)
FIGURE 11 SCHEMATIC OF TECTONIC BLOCKS
OF CAMBAY RIFT BASIN SEPERATED BY
TRANSFER FAULTS (MADAN MOHAN, 1995)
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Evolution of Basin The structural evolution of the basin can be categorized in three phases:
1. Syn-rift phase 2. Post-rift phase 3. Late post-rift phase
During the syn-rift phase, the basin tends to be of asymmetric nature and it characterized by
inter basinal highs and lows (figure 12). Reactivation of oblique faults and basinal uplifts
resulted in Devla-Malpur uplift (Broah-Jambusar block), Kalol uplift, Nawagam-Dholka high
(Ahmedabad block), Sanand-Jhalora uplift (Mehsana block) and Wayad and Wansa highs in
Patan block. The basin subsidence continued along the extensional faults (Mohan M, 1995).
The trappean fault activity ceases to a greater extent during post rift phase (Thermal
Subsidence stage) and the subsidence continued due to rapid crustal cooling and
sedimentary load deposited by principal fluvial systems.
Late post-rift phase is characterized by reverse separation along fault plane resulting in
structural inversion within the basin. It may be mentioned that this type of structural
readjustment within rift tectonics can be attributed to thermal contraction and isostatic
compensation of the sediments.
The Narmada geofracture was reactivated during post-Miocene time down throwing Broah-
Jambusar block considerably. The phases of basin evolution through syn-rift, post-rift and
FIGURE 12 GEOLOGICAL CROSS SECTION ALONG CAMBAY RIFT BASIN (MADAN MOHAN, 1995)
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structural inversion stages broadly confirm the tectonic cycles such as formative, negative,
oscillatory and positive put forth by Raju (1968).
Generalized Stratigraphy The formation of the Cambay Basin began following the extensive outpour of Deccan basalts
(Deccan Trap) during late Cretaceous covering large tracts of western and central India. The NW-SE
Dharwarian tectonic trends got rejuvenated creating a narrow rift graben extending from the
Arabian Sea south of Hazira to beyond Tharad in the north. Gradually, the rift valley expanded with
time.
During Paleocene, the basin continued to remain as a shallow depression, receiving deposition of
fanglomerate, trap conglomerate, trapwacke and claystone facies, especially, at the basin margin
under a fluvio–swampy regime. The end of deposition of the Olpad Formation is marked by a
prominent unconformity. At places a gradational contact with the overlying Cambay Shale has also
been noticed.
During Early Eocene, a conspicuous and widespread transgression resulted in the deposition of a
thick, dark grey, fissile pyritiferous shale sequence, known as the Cambay Shale. This shale sequence
has been divided into Older and Younger Cambay Shale with an unconformity in between. In the
following period, relative subsidence of the basin continued leading to the accumulation of the
Younger Cambay Shale. The end of Cambay Shale deposition is again marked by the development of
a widespread unconformity that is present throughout the basin.
Subsequently, there was a strong tectonic activity that resulted in the development of the Mehsana
Horst and other structural highs associated with basement faults.
Middle Eocene is marked by a regressive phase in the basin and this led to the development of the
Kalol/ Vaso delta system in the north and the Hazad delta system in the south. Hazad and Kalol/
Vaso deltaic sands are holding large accumulations of oil.
Major transgression during Late Eocene-Early Oligocene was responsible for the deposition of the
Tarapur Shale over large area in the North Cambay Basin. The end of this sequence is marked by a
regressive phase leading to deposition of claystone, sandstone, and shale alternations and a
limestone unit of the Dadhar Formation.
The end of the Palaeogene witnessed a major tectonic activity in the basin resulting in the
development of a widespread unconformity.
During Miocene the depocenters continued to subside resulting in the deposition of enormous
thickness of Miocene sediments as the Babaguru, Kand and Jhagadia formations.
Pliocene was a period of both low and high strands of the sea level, allowing the deposition of sand
and shale.
During Pleistocene to Recent, the sedimentation was mainly of fluvial type represented by
characteristic deposits of coarse sands, gravel, clays and kankar followed by finer sands and clays,
comprising Gujarat Alluvium.
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Throughout the geological history, except during early syn– rift stage, the North Cambay Basin
received major clastic inputs from north and northeast, fed by the Proto–Sabarmati and Proto–Mahi
rivers. Similarly, the Proto–Narmada river system was active in the south, supplying sediments from
provenance, lying to the east.
FIGURE 13 GENERALIZED STRATIGRAPHY OF THE CAMBAY BASIN
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Petroleum System Source Rock:
Thick Cambay Shale has been the main hydrocarbon source rock in the Cambay Basin. In the
northern part of the Ahmedabad-Mehsana Block, coal, which is well developed within the
deltaic sequence in Kalol, Sobhasan and Mehsana fields, is also inferred to be an important
hydrocarbon source rock. The total organic carbon and maturation studies suggest that
shales of the Ankleshwar/Kalol formations also are organically rich, thermally mature and
have generated oil and gas in commercial quantities. The same is true for the Tarapur Shale.
Shales within the Miocene section in the Broach depression might have also acted as source
rocks.
Reservoir Rock:
There are a number of the reservoirs within the trapwacke sequence of the Olpad
Formation. These consist of sand size basalt fragments. Besides this, localized sandstone
reservoirs within the Cambay Shale as in the Unawa, Linch, Mandhali, Mehsana, Sobhasan,
fields, etc are also present.
Trap Rock:
The most significant factor that controlled the accumulation of hydrocarbons in the Olpad
Formation is the favorable lithological change with structural support and short distance
migration. The lithological heterogeneity gave rise to permeability barriers, which facilitated
entrapment of hydrocarbons. The associated unconformity also helped in the development
of secondary porosity.
Cap Rock:
Transgressive shales within deltaic sequences provided a good cap rock.
Timing of migration & Trap formation:
The peak of oil generation and migration is understood to have taken place during Early to
Middle Miocene. (DGH)
Thermal History The thermal history of the basin is characterized by initial high heat flow followed by cooling
as the rift aborted. The average heat flow is of the order of 2.07 HFW. The normal
geothermal gradient is of the order by 34-40 °C/km and at places it goes upto 50-60 °C/km.
Very high thermal anomaly is observed around Cambay-Kathana area in Cambay-Tarapur
tectonic block. In general, in rift tectonics, the high heat flow zone can be attributed to
lithospheric thinning. Interestingly, this part of the basin is characterized by high gravity
anomalies, Bouger anomaly +37 mgals. (Madan Mohan, 1995).
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Source Potential Favorable thermal history with high
heat flows followed by cooling effect
has facilitated for generation and
preservation of hydrocarbon in the
Cambay Basin. The syn-rift organic
rich Cambay Shale constitute the
principle source facies of kerogen
type II/III and total organic carbon
(TOC) is higher in the northern basin
(figure 14), whereas maturity level is
higher in the south.
Early oil generation and expulsion
took place in the northern part of the
basin, isotope and biomarker studies
indicate subsequent entrapment
close to the source facies thus
undergoing short distance migration.
At places, low maturity (VRo =0.4-0.5)
oil in Mehsana sub-block is attributed
to oil generation from coal. The
source potential towards the
northern part of the basin, i.e. in
Tharad and Sanchor appears to be
deposited in lacustrine environment.
In the southern part, the oil
generation took place since Middle
Eocene and basin wide oil migration
took place in Early Miocene time.
(Madan Mohan, 1995).
FIGURE 14 TOTAL ORGANIC CARBON (TOC) CONTOUR IN CAMBAY
SHALE
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Petroleum plays Structural Highs and fault closures & Stratigraphic traps (pinchouts / wedgeouts, lenticular
sands, oolitic sands, weathered trap) in Paleocene to Miocene sequences have been proved
as important plays of Cambay Basin.
1. Paleocene – Early Eocene Play:
Formations: Olpad Formation/ Lower Cambay Shale.
Reservoir Rocks: Sand size basalt fragments & localized sandstone. Unconformities
within the Cambay Shale and between the Olpad Formation and the Cambay Shale
have played a positive role in the generation of secondary porosities. The Olpad
Formation is characterized by the development of piedmont deposits against fault
scarps and fan delta complexes.
2. Middle Eocene Play:
Formations: Upper Tharad Formation
Reservoir Rocks: In Southern part, Hazad delta sands of mid to Late Eocene & in the
Northern part the deltaic sequence is made up of alternations of sandstone and shale
associated with coal. Plays are also developed in many paleo-delta sequences of Middle
Eocene both in northern and southern Cambay in the Northern Cambay Basin; two
delta systems have been recognized.
3. Late Eocene – Oligocene Play:
Formations: Tarapur Shale, Dadhar Formation.
Reservoir Rocks: This sequence is observed to possess good reservoir facies in the
entire Gulf of Cambay. North of the Mahi River, a thick deltaic sequence, developed
during Oligo–Miocene, has prograded upto south Tapti area.
4. Miocene Play:
Formations: Deodar: Formation (LR. Miocene), Dhima Formation (Mid Miocene), Antrol
Formation (Upper Miocene)
The Mahi River delta sequence extends further westward to Cambay area where
Miocene rocks are hydrocarbon bearing. (DGH)
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Case Study I: Enhanced Oil Recovery by In-Situ Combustion (ISC) Technique in Balol and Santhal Fields, Mehsana
The northern part of Cambay basin
has a belt of heavy oil fields.
Santhal and Balol are two such
major fields located in the Mehsana
block, having API gravities 15o-18o.
In-situ combustion technique has
been implemented in these fields
to enhance the recovery of oil.
FIGURE 15 BALOL AND SANTHAL FIELDS IN CAMBAY BASIN (G.K
PANCHANAN, 2006)
Background Balol field was discovered in 1970 and put on production in 1985 through conventional
cased vertical wells drilled at 22 acre spacing.
Artificial lifts like Sucker rod pumps and screw pumps were used for cold production in Balol
and Santhal. However, the primary recovery was low, of the order of 13% due to adverse
mobility contrast between oil and water. (Har Sharad Dayal et.al, 2010)
Steam injection and ISC were the two options considered. But, steam injection could not be
implemented owing to depth of 1000m, presence of strong water drive and a pay thickness
of 5m. This left ISC as the choice for pilot testing.
Geology The Balol field is about 13 km in length forming N-S trending homocline dipping 3-5◦. Oil is
distributed in four oil bearing sands i.e. U, K-1 & K-II sands in Kalol formation and Lower Pay
formation from top to bottom. These pay sands were deposited during the early and middle
Eocene period and represent the characteristic regressive cycle intervening between two
major transgressive shale deposits. Kalol formation accounts for 95% of the field OOIP.
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K-1 is the major pay of Kalol formation and is spread throughout the field. (Har Sharad Dayal
et.al, 2010)
Santhal field has N-S trending anticlinal structure dipping 3-5◦ from west to east. There are 5
pay sands namely USP, KS-1, KS-II, KS-III and Lower stack. The reservoir facies pinch out up-
dip against the Mehsana horst.
Reservoir & fluid properties K-, in the Balol field, has porosity of the order of 28% and permeability of about 8 Darcy. Oil
is highly viscous and at reservoir temperature of 70 oC and pressure of 105 kg/cm2. The
viscosity varies between 150 to 1000 cP throughout the field. Oil saturation of K-1 sand is
77%. The solution GOR is 20-26(v/v) and the initial FVF is 1.05.
In the Santhal field, the reservoirs have average porosity of 28% and permeability ranging 3-
5 Darcies. The reservoir oil viscosity increases from south to north, from 50-200 cP (S.K
Chattopadhyay et.al, 2004). The oil in Santhal field contains around 9-9.5 % asphaltenes and
10-13% resins.
ISC implementation In Balol field, the process was tested in the laboratory and in the field on a pilot & semi-
commercial scale prior to commercialization in 1997. The commercialization process was
done in two phases- Phase I and Phase II and it was based on the Nelson & Mc Neil
approach.
In Santhal field, the ISC process was executed in KS-1 reservoir adopting an inverted 5 spot
injection-production pattern in the north western part. But, during commercial application,
it was changed to up-dip line drive (S.K Chattopadhyay et.al, 2004).
ISC process Both in Balol and Santhal fields artificial ignition was carried out using Gas Burner as
opposed to spontaneous combustion. This is because with artificial ignition, high vertical
sweep can be achieved. Also, the chances of oil saturation close to the wellbore become
less. So, if there is unplanned stoppage of air injection, the chances of backflow of flue gases
into the injection wells is minimised.
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Crestal line drive air injection was formulated taking the assistance of gravity, in both the
fields. This helps in nullifying the heterogeneity and pertains to less handling of flue gases as
part of it remains as gap cap.
In order to enhance sweep efficiency, wells in both the fields are subjected to wet
combustion, which involves injection of pre-estimated volume of air in a cycle of six days
followed by one-day water (S.K Chattopadhyay et.al, 2004).
Production performance Balol field: In phase 1 of the ISC implementation, pre-initiation cold oil production was about
60 m3/d with water cut of 80%. With air injection, the oil production increased to 260 m3/d
with reduction of average water cut from 82% to about 40% (Figure 16).
FIGURE 16 CROSS PLOT OF AIR RATE
& OIL PRODUCTION RATE IN PHASE I (HAR SHARAD DAYAL ET.AL, 2010)
In Phase II oil production rate increased up to 500 m3/d. Air injection peaked in 2004 at the
rate of 0.5 MM S m3/d. Meanwhile, the oil production has shown a linear increase with air
injection rate (Figure 17). Up to 2010, 960 MM Sm3 of air has been injected, yielding 0.63
MM m3 of incremental oil (Har Sharad Dayal et.al, 2010).
FIGURE 17 CROSS PLOT OF AIR RATE & OIL PRODUCTION RATE IN PHASE II (HAR SHARAD DAYAL ET.AL, 2010).
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In Santhal field, 23 injectors have been drilled and they have improved the production of oil
by around 540 tons/day over the base production in a time limit of 5 years (S.K
Chattopadhyay et.al, 2004). In fact, many wells which were operating under Artificial lift
prior to ISP process, are now operating under self-flow mechanism.
Issues Rupture of Downhole-equipment at high temperature and high pressure: 2 incidents of
bursting of 3rd stage air compressors had taken place in Santhal field. Flow back of flue gases: Breakthrough of flue gases along with air have been noticed in
the Balol field in 2006, due to annular leakage in one injector well. Drilling of new injector wells with right casing policy, cementation and metallurgy for tubing is required.
Highly costly technique. Combustion started at the injector results in hot produced fluids that often contain unreacted oxygen. These conditions require special, high-cost tubular to protect against high temperatures and corrosion. More oxygen is required to propagate the front compared to forward combustion, thus increasing the major cost of operating an in situ combustion project.
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Case Study II: Enhanced Oil Recovery by Alkaline Surfactant Flooding (ASP) Technique in Jhalora Field
Jhalora field is located in the western margin of Ahmedabad-Mehsana tectonic block of
Cambay basin (Figure 18). It was discovered in 1967. This field was put on production in
1978. Reservoir and crude oil properties of all the three main producing sands K-III, K-IV and
K-IX+X are quite different. All these sands are operating under edge water drive. Jhalora K-IV
sand is producing oil at an average rate of 227 ton/day through 29 wells, with an average
water cut of 84 % (as on Oct’2011). The mature stage of the Jhalora K-IV with
heterogeneous reservoir characteristics and unfavorable mobility ratio makes it an ideal
choice for application of chemical EOR technique to enhance the recovery. (Jain, Dhawan, &
Mishra, 2012)
FIGURE 18 TECTONIC MAP OF CAMBAY BASIN (DEBASHIS ET AL., 2008)
Reservoir Characteristics KIV sand of Jhalora oil field is heterogeneous in character. There is also large variation in
viscosity of the reservoir oil (ranging from 30 to 50 cP at reservoir temperature) with
adverse mobility ratio are the reasons for high water cut/production behavior of the wells.
The build-up studies indicate wide variation in the permeability. Core collected during
laboratory studies confirms the same. The permeability data obtained through build-up
studies varies between 1.9 to 8.7 Darcy. The sand K-IV mainly consists of sandstone which is
medium to dark gray, compact in nature. The major framework mineral for the unit is
quartz. Pyrite is present in traces. Crude oil is acidic in nature which helps in in-situ
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generation of surfactant in presence of alkali. As on date, most of the wells are producing on
artificial lift with high water cut. Reservoir parameters of K-IV sand is given in table 2:
TABLE 2 RESERVOIR PARAMETERS OF JHALORA K-IV SAND (JAIN, DHAWAN, & MISHRA, 2012)
S.No. Parameters Value
1 Average Depth, m (MSL) 1265
2 Average pay thickness, m 7-9
3 Temperature, OC 82
4 Initial Reservoir Pressure, kg/cm2 140
5 Current Reservoir Pressure, kg/cm2 ~127
6 Saturation pressure, kg/cm2 99
7 Initial Oil Saturation Soi, % 58 - 73
8 Porosity, % 28 - 32
9 Permeability range, Darcy 1.9 – 8.7
10 Oil Viscosity at reservoir temp., cP 30 - 50
11 Oil density, g/cc 0.9201
12 Formation Water Salinity(mg/l) 11291
The mature stage of the field with heterogeneous reservoir and unfavorable fluid
characteristics makes it an ideal choice for application of chemical process an EOR technique
to enhance recovery. Based on properties of the K-IV sand and screening criteria (attached in
Appendix) in the table above, ASP was chosen as the EOR technique to be applied in the
field.
Before Field implementation, Extensive lab and Simulation studies were done by Institute of
Reservoir Studies (IRS)-ONGC, Ahmedabad. Results of these studies are summarized in the
following points:
envisage incremental displacement efficiency of about 23% of OIIP Pilot design envisage injection of 0.3 Pore Volume (PV) ASP slug (2.5 wt% Sodium
Carbonate, 0.25 wt% surfactant and 1500 ppm of polymer) 0.3 PV graded polymer buffer (three slugs of 0.1 PV each with polymer concentrations 1200, 800 and 400 ppm) followed by 0.4 PV chase water
ASP injection rate of 150m3 /day was recommended Inverted 5-spot pattern pilot was designed
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Field Implementation In view of heterogeneous reservoir and unfavorable fluid characteristics, polymer gel based
profile modification job was carried in the ASP pilot injection well JH #I prior to
commissioning of ASP pilot. After that pre-flush of 2% NaCl was injected followed by 16 m3
of tracer (Ammonium Thiocyanate) injection. ASP pilot project started functioning from 07th
February 2010.
FIGURE 19 SCHEMATIC MAP OF JHALORA ASP PILOT AREA (JAIN, DHAWAN, & MISHRA, 2012)
Where, JH# I: Injection well
JH# A, B, C and D: Production wells
JH# E and F: Offset monitoring wells
Production Performance of ASP pilot producers Combined performance of six pilot producers in terms of oil rate and water cut is given in
(Figure 20). Reduction in water cut in all the pilot producing wells was observed since start
of the ASP injection in JH#I. From this plot it can be seen that the oil rate has been increasing
gradually and water cut is reducing at the same time. Cumulative oil gain till Oct’ 2011 is
about 47000 barrels.
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FIGURE 20 COMBINED PERFORMANCE OF SIX JHALORA ASP PILOT PRODUCERS (JAIN, DHAWAN, & MISHRA, 2012)
Conclusion and Further Plan Initial performance of ASP pilot producers is very encouraging. Reduction in water
cut and increase in oil rate is observed in pilot producers. ASP performance is as per prediction.
Water softening plant is needed to control high turbidity. Simulation study is in progress for possible pilot expansion.
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Case Study III: Enhanced Oil Recovery by Polymer Flooding Technique in Sanand Field
Background Sanand is the only field in India where field scale polymer flooding is going on for the last
twelve years. The field was discovered in 1962 and commercial production commenced from
1969. Oil viscosity of 20 cP led to adverse mobility ratio which resulted in cusping of water in
structurally higher wells. Hence polymer flood was considered the best option for improving
mobility ratio of oil and overall areal and volumetric sweep efficiency. KS-III sand is the major
hydrocarbon bearing sand in the field with 64% of proved oil-in-place and 95% of total oil
production. (Deepti Tiwari, 2008)
General Geology Sanand field is located at the western margin
in the southern part of the Ahmedabad –
Mehsana tectonic block of Cambay basin.
Structure consists of an elongated doubly
plunging anticline NNW-SSE. Sanand is a
multi-layered reservoir in Kalol sands but KS-
III is the main reservoir, which belongs to
Kalol formation of Eocene age (Deepti
Tiwari, 2008). The structure is dissected by a
number of faults dividing it into many sub
blocks. The faults have limited throw in the
range of 5-15 m but due to thin reservoir
interval interbeded within shales, these
faults appear locally as effective permeability
barriers. The section is dominated by
interbeded sands, silts, shales and coals,
interpreted as a combination of marine,
coastal marsh and deltaic flood plain
environment (S.K.Sharma, 1997).
Reservoir and Fluid properties Reservoir properties in KS-III sands are in general, good. The reservoir is made of silty
sandstone at a depth of 1300 m containing oil of 20 cP viscosity at 85oC (reservoir
temperature). Average permeability is 1000 md and varies from 3.4 md to 7d. Average sand
thickness is 7 m and porosity is in the range of 24-32%.Initial reservoir pressure was 142
Kg/cm2 at 1325 m datum depth which declined to 100 Kg/cm2. Crude is under saturated
with bubble point pressure of 80 Kg/cm2 (Deepti Tiwari, 2008). Mixed drive mechanism is
FIGURE 21 LOCATION MAP OF SANAND FIELD (CHANCHAL
DASS, 2008).
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present with a gas cap support from western flank and a weak aquifer support from eastern
flank.
Field Implementation of Polymer EOR Technique The production from Sanand Horizon-III started
in 1969. Main problems encountered in the
field during the course of production were high
GOR in Crestal wells, water cut and decline in
average reservoir pressure. Simulation studies
indicated a recovery of 14.9% OIP by primary
methods. ONGC has implemented a large scale
polymer flood project in Sanand oil field. In
April, 1985, an experimental pilot project had
started in an area of 141 acres of Sanand
Horizon-III. Polyacrylamide polymer of
concentration 400 ppm and 15 % pore volume
slug size was chosen for field injection on the
basis of laboratory experiment. As evident from
figure, the pattern was an asymmetrical
inverted five spot with 4 producers, 1 injector
and 1 monitoring well. The scheme comprised different stages which included:
A) Pre-flushing of the reservoir with tube well water
B) Injection of polymerized water of different concentration
C) Injection of chase water
Average injection and production rates of the pilot wells were optimised for uniform and
radial movement of flood front. Before the polymer injection, KI of concentration 250 ppm
was added as a tracer with first batch of pre-flush water (S.K.Sharma, 1997).
Expanded Pilot Phase(EPP): On successful pilot completion, the expanded pilot phase
commenced in Feb. 1993. Its size was approximately 338 acres and this phase had four
inverted 5 spot patterns with 9 producers and 4 injectors (Mahendra Pratap, 1997).
Field-wide Commercial Application: Total area
covered in the beginning was 1039 acres with 32
producers and 16 injectors. It was designed on the
basis of simulation studies (Mahendra Pratap,
1997).
FIGURE 22 PILOT WELLS AND EXPANDED PILOT PHASE
WELLS (MAHENDRA PRATAP, 1997).
FIGURE 23 WELLS IN COMMERCIALISATION AREA
(MAHENDRA PRATAP, 1997).
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Performance Monitoring The main objective of polymer injection is to improve oil recovery from the field with
reduced water cut. So maintenance of injection polymer quality and quantity is vital for the
success of polymer flood project. The parameters that were selected for the monitoring
purpose included salinity determination of the produced water, tracer concentration; water
cut data and polymer concentration. PLT study, Pressure Fall Off study and Pressure Build-up
tests, Temperature survey and Flow meter survey are also carried out regularly. The
production and the injection data are continuously collected and monitored for the
identification of the various problems and implementation of the corrective measures.
Echometer surveys are conducted periodically to measure fluid level and reservoir pressure
(Mahendra Pratap, 1997). Monitoring also includes checking quality of injected water for
chemical, mechanical and bacteriological degradation by measuring turbidity, dissolved
oxygen, iron content, salinity and pH factor both at polymer tank and injection lines. Physical
cleaning and disinfection of polymer tanks and flowlines, proper removal of dissolved
oxygen by oxygen scavengers, biocide dosing to reduce bacterial effect are some of the steps
taken from time to time. Injectivity tests are conducted in polymer/chase water injectors
from time to time and corrective measures are taken (Deepti Tiwari, 2008).
Production Performance The results before and during the polymer injection of the pilot phase are shown in figure. It
is evident that there is profile improvement as a result of polymer injection which indicates
that polymer had a beneficial effect on injection well. Change in resistance factor (ratio of
mobility of water to mobility of polymer) was also observed with the help of PFO tests and it
was found that RF increases with increase in polymer concentration. Production response to
polymer injection during EPP was also encouraging (Mahendra Pratap, 1997). In April 2008,
the sand has produced oil at rate of 232m3/d with 68% water cut from 44 producers. A total
of 508 m3/d of polymer solution had
been injected through 9 wells along
with 683 m3/d of chase water through
9 wells (Deepti Tiwari, 2008).
FIGURE 24 PERFORMANCE OF EXPANDED POLYMER PILOT
(MAHENDRA PRATAP, 1997).
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Innovation in EOR techniques Page | 40
FIGURE 25 PERFORMANCE OF SANAND POLYMER FLOOD PROJECT (CHANCHAL DASS, 2008).
Field Review Performance review, using reservoir simulation, has been carried out from time to time and
exploitation strategy has been planned /modified accordingly. Simulation study of 1984
predicted depletion recovery of 14%. After initiation of polymer injection, simulation studies
were carried out in a Black oil simulator with polymer option. Again review was carried out
in 2007 to identify areas of by-passed oil, suggest in-fill locations and to assess requirement
and effect of polymer injection. Recovery of 35% is predicted by 2020. Polymer injection is
extended up to 2013 based on 25% of total pore volume injection (Deepti Tiwari, 2008).
Pre-Project Dissertation Report
Innovation in EOR techniques Page | 41
Case Study III: Enhanced Oil Recovery by Alkaline Surfactant Technique in Viraj Field
The Viraj oil field lies in Ahmedabad-Mehsana
tectonic block of Cambay Basin. The field was
discovered in 1977 and was put on production in
1980. The applicability of Alkaline-Surfactant-
Polymer (ASP) flood process in Horizon-IX+X in Viraj
field was established on the basis of laboratory
investigations in 1992. The results of laboratory
displacement studies and performance prediction
indicated that ASP flood in Viraj field could produce
incremental oil in the range of 18-24% of OIIP over
water flood. It was, however, believed that the
process needs to be evaluated on pilot scale to test
the laboratory results under actual field conditions
and also to fine tune the process parameters.
Accordingly, an ASP pilot was commissioned with
four inverted 5–spot patterns in a limited portion
(68 acres; 276,831 m2) in northern part of Viraj field
Field history Viraj field was discovered in 1977 with drilling of an exploratory well-Viraj-1. A technological
scheme was prepared in 1981. Simulation studies carried out in 1985 indicated a recovery of
24.6% of OIIP by the year 2001. Main problems encountered in the field during the course of
production were high water cut, sand-cut and frequent down-hole chocking of perforations
and tubing due to asphaltic nature of the crude oil. The field has been developed with a
close spacing of 200-250 metres and there is little scope for infill drilling to increase the
ultimate recovery. In view of the Petrophysical properties of reservoir and characteristics of
crude oil, ASP flooding emerged as most suitable EOR process for achieving maximum
recovery.
Reservoir Description The presence of oil and gas in Viraj field was established in Kalol equivalent pay zones VIII,
IX+X, Chhatral member of Kadi formation and C+D. Pay zone IX+X, the main producing
horizon, is subdivided into two layers viz. L1 and L2 separated by coal shale band of 4-5 mts.
The structure of the field is a doubly plunging anticline trending NNE-SSW. The southern
flank of the structure is dissected by a fault forming the western limit (Figure 26).
Lithologically, rock is composed of brownish grey, coarse to medium grained, moderate to
FIGURE 26 ASP PILOT LOCATION IN VIRAJ FIELD
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Innovation in EOR techniques Page | 42
good sorted sandstone, siltstone Average depth is 1300 metres and the average pay
thickness is 15 metres.
TABLE 3 RESERVOIR DESCRIPTION OF VIRAJ FIELD:
Area weighted average porosity is 30% and permeability determined by pressure
transient tests ranges from 4.5 to 9.9 Darcies (Table 3). The gravity of the oil averaged 18.9
degree API and the viscosity at reservoir conditions of 136 kg/cm2 and 81o c was 50 cp. The
pour point is 15oCand salinity is 13.25 mg/lit. The crude oil is having 4.48 % asphaltenes,
5.67 % wax content and 18% resin by weight. The Viraj crude is acidic in nature, having acidic
component 1.8520 mg KOH/gm. of crude oil (Table 4). The initial reservoir pressure i.e. 136
kg/cm2 has marginally declined to 126 kg/cm2 after a cumulative oil production of 18.9 % of
OIIP. It shows that reservoir is operating under active water drive.
TABLE 4 CRUDE OIL PROPERTIES IN VIRAJ:
TABLE 5 CHARACTERISTICS OF SURFACTANT USED IN VIRAJ:
CHARACTERISTICS OF SURFACTANT
Name Petroleum Sulphonate (HLA)
Nature Anionic
Activity 60%
Thermal Stability Stable at 81oC
Solubility Soluble in water & Oil phase
CMC value 0.20 wt%
IFT between Viraj crude oil & tube well water having 0.20 wt% Surfactant & 1.5 wt% Sod. carbonate
0.61 mill dynes / cm
RESERVOIR DESCRIPTION
Lithology Sandstone
Avg. Depth (mts.) 1300
Avg. Pay thickness (mts.) 19
Porosity (%) 30
Permeability Range (Darcy) (Build-up) 4.5 to 9.9
Reservoir Temp. (O C) 81
Initial Res. Pressure (Kg/Cm2) 136
Current Res. Pressure (Kg/Cm2) 126
Drive Mechanism Active acquirer
CRUDE OIL CHARACTERISTICS
Oil gravity ( o API ) 18.9
Oil Viscosity (cP) 50
Asphaltenes (% w/w) 4.48
Wax content (% w/w) 5.67
Resin (%) (w/w) 18
Acidic component (mg-KOH/gm) 1.8520
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Innovation in EOR techniques Page | 43
Field implementation: Surface Facilities and Operation. Surface facilities were created for storage of tube well
water, storage of Alkali Surfactant and Polymer Solutions mixing the chemicals, injection of
different on-line doses and injection of prepared slugs to injectors. Facilities for handling the
produced fluids were already existing in Viraj field. The injection plant was designed to
minimize the manpower requirement. Plant design parameters included facilities to inject
liquid @ 800 m3/d.
Data Acquisition With a view to closely monitor the performance of the pilot, a comprehensive data
acquisition strategy was formulated. The data acquisition programme included:
Injection details viz. the actual injection rate, volume and stabilized injection pressure for each injector separately.
Parameters of the injected fluid like concentration, Turbidity, PH etc. for Pre-flush, ASP slug and mobility buffer prepared in each tank.
Continuous recording of production details including production rate, water cut etc. for each producer separately.
Record of consumption of each chemical on daily basis with a view to plan the action for procurement of Chemicals in time.
As all the wells of the pilot are operating on SRP, echo meter studies are carried out under both dynamic and static conditions at regular intervals.
Production logging was planned for all the injection wells periodically to get information regarding injection profile near the well bore and also to detect the presence of high permeability streaks, if any.
In order to understand the pattern of fluid flow through the matrix, the presence of tracer is being monitored in the samples collection from all the pilot and offset producers.
Samples from both production and injectors are also analysed at regular interval for bacterial presence and suitable biocide treatment would be given in case of high bacterial counts.
TABLE 6 PARAMETERS MONITORED DURING IMPLEMENTATION:
PARAMETERS MONITORED
Parameters ASP Slug Mobility Buffer Chase Water
Concentration
Alkali (Wt %) 1.5 ± 0.01 - -
Surfactant, ppm 2000 ± 40 - -
Polymer, ppm 800 ± 20 + 20 -
Turbidity, NTU < 10 < 10 < 10
Dissolved O2 ,ppm < 1.2 < 1.2 < 1.2
Iron, ppm < 1.5 < 1.5 < 1.5
Salinity gm/lit 5 < 3 < 3
pH 10-11.5 7.7- 9.0 7- 8.5
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Results Performance of the pilot area wells just prior to the commencement of ASP pilot on 10th
August 2002 indicated that 9 wells were producing oil @ 24.4 m3/d with an average water
cut of 83.5%. Performance of these wells during the first phase i.e. ASP injection is
encouraging as there is improvement in oil rate from 24.4 m3/d to 98.23 m3/d. Average
water cut has also reduced from 83.5% to 71.4 %.
Conclusion ASP (Alkaline-Surfactant-Polymer) flooding has shown encouraging results improving
recovery over water flood during laboratory studies. Pilot is under way to test the efficacy of
the process under actual field conditions and also to fine tune the process parameters.
Significant conclusions of the efforts made so far may be summarized as follows:
Reservoir rock and fluid properties were studies in detail before ASP flooding was identified as potential EOR technique to improve recovery efficiency in Viraj field.
Suitable chemicals identified for successfully implementing ASP pilot in Viraj are: o Sodium Carbonate as alkali. o Petroleum Sulphonate as surfactant, and o Partially hydrolyzed Poly acrylamide (PHAA) as Polymer.
Laboratory tests were conducted to: o Optimize ASP concentrations o Formulate Injection Strategies o ASP slug design o Defining mobility buffer sequence.
Performance evaluation during the first phase of the pilot shows encouraging results in terms of both improvement in oil rate and reduction in Water cut.
Indication of in-situ emulsion formation shows the efficacy of ASP flooding during this phase of the pilot.
Polymer / Tracer break through needs close monitoring in producing wells to understand the preferential flood-front movement.
Successful field implementation requires continuous efforts and close field monitoring of the pilot to test the efficiency and effectiveness of ASP flooding as potential EOR technique.
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Innovation in EOR techniques Page | 45
Economic analysis of EOR projects
Identification of major costs
Field development expenditures
Drilling and completion: Drill sufficient new production wells to provide the required acre spacing; drill sufficient injection wells to provide the injection pattern.
Work over and conversion: Bring existing production and injection wells to acceptable quality.
Equipment expenditures
Well, lease, and field production equipment: Install equipment necessary to operate new production wells.
Injection equipment: Install equipment necessary to operate new injection wells. Separation and compression equipment: Install sufficient equipment to produce
maximum yearly requirement for recycle indicants.
Operating and maintenance costs
Normal operating and maintenance costs: over normal daily operation, surface repair and maintenance, and subsurface repair, maintenance and services (include artificial lift of primary production).
Incremental injection operating and maintenance costs: Cover incremental operating and maintenance costs due to injection operation and increased fluid handling ,
Injection material costs
Purchased injectants: Inject the specified reservoir pore volume of recycle indicants over the determined time period.
Recycled injection fluids: Inject reservoir pore volume of recovered injectant from production (per injection schedule for recycle injectant)
Other costs
1. Field study, engineering, and supervision: Provide research, development, and management support to the project.
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Innovation in EOR techniques Page | 46
Evaluating the NPV and ROR for an EOR project To evaluate the technical and economic feasibility of any project, let alone any EOR project,
the Net Present Value (NPV) and the Rate of Return (ROR) are two very fundamental
parameters.
The Net Present Value for a time series of cash flows is defined as the sum of the
Present Values (PV) for all the cash flows; whether outgoing or incoming for the project. It
is a tool to evaluate the present values of future investments, taking into account inflation
as well as the returns expected from the project. An NPV>0 points to a project that will be
profitable in the future, NPV<0 points to an unprofitable project and NPV=0 points to a
situation where some changes might have to be made to get the project approved.
In the case of EOR projects, during the initial few years, when the project is being
established, the cash flows will mostly be negative as they will deal with the costs of
installing new surface facilities, drilling new injection wells, cost of chemicals, cost of
injection gas, additional pumping and compression facilities etc. However, once the EOR
project has been pilot tested and moves to the full field application, then one can
start expecting positive cash outflows soon. These positive cash outflows will not be directly
seen by the user as the chemicals or gas injected will not contribute greatly to it. The
real contribution to the positive cash flows in such cases will be the amount of incremental
oil that we will be able to produce. More the sweep efficiency more is the amount of
extra oil produced and more will be our profits. This will then reflect in an increased
NPV of the project.
The NPV is calculated as shown below:
NPV = a/ (l + r) n………………………………………… (1)
Where,
NPV= Net Present Value
a=Summation of cash flows
r=Rate of return
n=number of years
The Rate of Return (ROR) can be calculated as the amount of money earned or lost on
an investment divided by the total amount invested in the project. It is another tool use to
gauge the economic feasibility of an EOR project. Higher the ROR, more profitable it is to
implement the project. In the equation for the NPV, the internal rate of return (IRR) is
that value of the rate of return that makes the NPV from the project equal to zero.
The IRR doesn’t take into account the interest rate or the inflation, only the internal
factors affecting the cash flows.
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Innovation in EOR techniques Page | 47
For calculating the net cash flow, equations of the type shown below can be used:
CF= (NP*Po – ORR – FC -- O&M – INV) -TAX ………………………... (2)
Where,
CF= Cash Flow
Np=Yearly Oil Production
Po=Oil Price
FC=Steam cost
O&M= Operation & Maintenance Cost INV=Investment
TAX=Amount paid as tax
This above written equation (2) is used for calculating the cash flow for steam flooding
projects.
___________________________________________________________________________
CF = (FOPT * $/bbl) - (FICIT * $/ton) - (FIWIT *$wat) - (FWPT * $dwat) + (FCO2STR *
$TAX/ton) ……………………………... (3)
Where,
C=Total cash inflow, $
$/bbl=Price of oil per bbl, $
$/ton=cost of CO2 injection per ton, $
$wat=cost of water injection per bbl, $
$dwat=cost of water disposal per bbl, $
$TAX/ton=Tax credit of CO2 stored per ton,
$FOPT=Cumulative oil production, STB
FWPT=Cumulative water production, STB
FICIT= Cumulative CO2 injection, ton
FIWIT=Cumulative water injection, STB
FCO2STR=Cumulative CO2 stored, ton
This above written equation (3) is used for calculating the cash flow for CO2 Injection
projects.
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Innovation in EOR techniques Page | 48
EOR Project Risks
Higher oil prices and concerns about future oil supplies are leading to increased interest
in EOR processes around the world. Even small incremental improvements in recovery
efficiency can add significant reserves. Because EOR projects are generally more expensive
and involve higher front end costs than conventional secondary projects, effective planning
takes on added importance. Good EOR planning combines modeling and economic studies
at each step throughout the engineering design process. Experience tells us that a great
deal of wasted time and effort can be avoided in this way. Different type of Risks associated
with EOR projects are discussed below in brief:
1. Reservoir Response: In many EOR projects the biggest risk is that the reservoir does not respond as predicted. The key variable is revenue, the product of oil production and crude price. The second most important variable is investment either capital or injectant. The oil production rate is not sufficient to cover economical loss.
2. Oil Prices: Crude price is the other important variable. Unfortunately, it is one than none of us can control. It is also one that none of us can predict with assurance. Along with the cyclical nature of the oil and gas industry, product prices can also vary unexpectedly during significant political events such as war in the Middle East, over production and cheating by the OPEC cartel, interruptions in supply such as large refinery fires, labor strikes, or political uprisings in large producing nations (e.g., Venezuela in 2002), and changes in world demand.
3. Political Risk: Government tax policies and incentives change with time. (Today’s attractive “incentive” can become tomorrow’s unattractive “loop hole”.) Significant amounts of the world’s hydrocarbon reserves are controlled by nations with unstable governments. Companies that invest in projects in these countries take significant risks that the governments and leaders with whom they have signed contracts will no longer be in power when earned revenue streams should be shared contractually. In many well-documented cases, corporate investments in property, plants, and equipment are simply nationalized by local governments, leaving companies without revenue or the equipment and facilities that they built to earn that revenue.
4. Infrastructure and Source Reliability: Most EOR processes require some input – CO2, heat, chemicals, fuel, etc. Can these be made available at affordable prices? The challenge here is to take a very practical look at what is needed to accomplish the EOR project in the field.
5. Environmental Risk Different methods of EOR have different repercussions on the environment. These must be considered while taking the decision on the EOR to be used.
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Innovation in EOR techniques Page | 49
Major Economic Models used
Least-Squares Monte Carlo (LSM) method:
It provides a decision making tool that is able to capture the value of flexibility in
surfactant flooding implementation. The LSM method provides great insight into the
effect of uncertainty on decision making which can help mitigate adverse circumstances
should they arise.
System dynamics computer simulation model:
It is designed to
Allow rapid assessment of the economics of the EOR project
Evaluate the sensitivity of the economics to the parameters of the reservoir and to the efficiency of recovery process.
The EOR system variables are grouped in 4 different sectors
1. Field parameter sector
2. Fluid injection sector
3. Fluid recovery sector
4. Financial analysis sector
Merak Peep software:
It is software developed by Schlumberger for economic modeling of upstream oil and gas
projects. It is in continuous daily use by over 1,500 economists and engineers in
approximately 100 oil and gas companies across the world.
ECLIPSE Black oil reservoir simulator:
It offers EOR modeling options that allow comprehensive analysis. Most of the modern
EOR processes can be modeled using this simulator. It is also developed by Schlumberger.
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Innovation in EOR techniques Page | 50
EOR Economic Model: The characteristics of the reservoir and the costs of producing EOR oil in that reservoir are
entered into the models, which then generate estimate of:
The quantity of crude oil that will be produced from the project. A price sufficient to reimburse all costs of the project and provide an adequate
return on investment (ROI). The timing at which reserves in the reservoir will be produced. These estimates
are then aggregated for the overall estimates of daily production, cumulative production, and ultimate recovery.
General Structure of the Economic Model: The estimate of the amount to be
recovered through EOR application is based on actual reservoir parameters of oil
saturation, pore volume and previous primary and secondary recovery, the actual recovery
calculation differs among techniques. This estimate is displayed as total incremental EOR
production and incremental production per year from the time the project was initiated.
Cash Inflow: Production of Oil.
Cash Outflow: Investment cost, Operating Cost, field development expenditures,
equipment expenditures, operating and maintenance cost, injection material costs.
The production estimate is matched with investment and operating costs and various rates
of return to calculate the required price for the oil.
Financial Assumptions:
Date of cost assessment: The costs used are assumed to be applicable as of the date of initiating the project. As this model is used in future years, the specific cost parameters will need to be updated to reflect cost changes.
Sharing of costs: The model assume that well operating costs are shared between primary/ secondary and EOR production. For this assumption, a primary / secondary production decline curve was constructed for each reservoir.
Allocation of general and administrative (G & A) overhead costs : Based on the practices of numerous producing companies, the model assume project G & A cost per year equal to the following : twenty percent of basic and incremental injection operating and maintenance costs plus four percent of investment costs.
Distribution of tangible and intangible costs for drilling and completion: The model assumes that the company uses a successful efforts approach for its tax deduction. As a result , the following rules apply :
o Intangible costs equal to 70% of drilling and completion costs for production wells and 100% of work over costs are expended in the year incurred.
o Tangible costs equal to 30% of drilling and completion costs for production wells, plus 100% of all other well lease, and injection investment costs are expended (through depreciation) based on a unit of production approach.
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Innovation in EOR techniques Page | 51
Appendix
EOR
Tech
niqu
eG
ravi
ty
{API
}Vi
scos
ity (c
P)Co
mpo
sitio
nO
il Sa
tura
tion
(% P
ore
Vol)
Form
atio
n Ty
peNe
t Thi
ckne
ssAv
erag
e
Perm
eabi
lity
Dept
hTe
mpe
ratu
re
nitro
gen
& flu
e
gas
>35
<0.4
cPhi
gh %
of C
1-C7
>40%
sand
ston
e or
car
bona
teth
in u
nles
s di
ppin
gno
t crit
ical
>600
0ft
not c
ritic
al
HC m
isci
ble
>35
<10c
Phi
gh %
of
C2-C
7>3
0%sa
ndst
one
or c
arbo
nate
thin
unl
ess
dipp
ing
not c
ritic
al>4
000f
tno
t crit
ical
CO2
>22
<10c
Phi
gh %
of C
5-C7
>20%
sand
ston
e or
car
bona
tewi
de ra
nge
not c
ritic
al>2
500f
tno
t crit
ical
Imm
isib
le g
ases
>12
<600
cPno
t crit
ical
>35%
not c
ritic
alno
t crit
ical
not c
ritic
al>1
800f
tno
t crit
ical
Surfa
ctan
t
Floo
ding
>25
<30c
Plig
ht in
term
edia
tes
are
pref
erab
le>3
0%pr
efer
ably
san
dsto
ne>1
0ft
>20m
d<8
000f
t<2
00*F
Poly
mer
flood
ing
>15
<150
cP, b
ette
r
if 10
<cP
<100
cPno
t crit
ical
>50%
sand
ston
e pr
efre
d bu
t
carb
onat
eno
t crit
ical
>10m
d<9
000f
t20
0*F
Alka
line
Floo
ding
>20
<200
cPso
me
orga
nic
fluid
s ar
e
desi
rabl
e
abov
e
wate
rfloo
d
resi
dual
sand
ston
eno
t crit
ical
>20m
d<9
000f
t<2
00*F
Com
bust
ion
>10
<500
0cP
som
e as
phal
tic
com
pone
nts
>50%
high
por
osity
sand
ston
e>1
0ft
>50m
d<1
1500
ft<1
00*F
Stea
m>8
<200
000
not c
ritic
al>4
0%hi
gh p
oros
ity
sand
ston
e>2
0ft
>200
md
<450
0ft
not c
ritic
al
Gas
Inje
ctio
n M
etho
ds
Enha
nced
Wat
erflo
odin
g
Ther
mal
Met
hods
FIG
UR
E 2
7 J
J T
AB
ER
EO
R S
CR
EE
NIN
G C
RIT
ER
IA
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Innovation in EOR techniques Page | 52
TAB
LE 7
SC
RE
EN
ING
CR
ITE
RIA
FO
R A
SP
(S
HE
NG
, 2
01
3)
Prop
osed
by
µo (c
P)So
(fra
c.)k
(mD)
Tr (°
C)Fo
rmat
ion
wat
er
salin
ity (T
DS, p
pm)
Diva
lent
(ppm
)Lit
holo
gyCl
ay
Wel
l
Spac
ing
(ft)
Aqui
fer
Gas c
ap
Lake
et a
l. 19
92<2
00
Tabe
r et a
l (19
97a,
b)<3
5>0
.35
> 10
<93.
3
Al‐B
ahar
et a
l. 20
04<1
50>5
0<7
050
,000
1000
Sand
ston
eLo
wNo
No
Dick
son
et a
l. 20
10<3
5>0
.45
>100
<93.
3<2
0,00
0 if
T r<60
o C
<50,
000
if Tr
>60o
C
From
ASP
pro
ject
s12
.90.
347
352
7993
178
Sand
ston
eLo
w40
3.6
Wea
k in
few
case
sNo
Sum
mar
y of
scre
enin
g cr
iteria
for A
SP
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Innovation in EOR techniques Page | 53
References
1. Abdus Satter, 1994, Integrated Petroleum Reservoir Management, pg.177-189
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3. Ashok Kumar, Reservoir Nature and Evaluation of Deccan Trap Basement, Cambay Basin, India. The Society of Petrophysicists and Well Log Analysts India
4. C.E.Cooke, R. P. (1974, December). Oil Recovery by Alkaline Waterfiooding. Journal of Petroleum Technology, 1366-1369.
5. Dass, Chanchal et al.: “Monitoring of Polymer Flood Project at Sanand Field of India”, SPE 113552, Mumbai, India, March 2008.
6. Debashis Chakravorty, K. R. (2008). Integrated Geological Modeling Of a Mature Oil Field in North Cambay Basin, India. 7th International Conference & Exposition on Petroleum Geophysics (p. 1). Hyderabad: SPG.
7. Du, Y. and Guan L.: “Field-Scale Polymer Flooding:Lessons Learnt and Experiences Gained”, SPE 91787, Mexico, November 2004.
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(MOST): http://www.most.gov.mm/techuni/media/PE_05045_2.pdf 13. Enhanced Oil Recovery By In Situ Combustion Environmental Sciences Essay. (n.d.).
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14. In-Situ Combustion Technique to enhance Heavy-Oil Recovery at Mehsana, ONGC-A Success Story: A Doraiah, Sibaprasad Ray and Pankaj Gupta, ONGC, 2007,SPE 105248.
15. In-Situ Combustion: Opportunities and Anxieties: Har Sharad Dayal, B.V Bhushan, Sujit Mitra, S.K Sinha and Siddhartha Sur, SPE, ONGC,2010 SPE 126241.
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