Project PreDissertation Report -Enhanced Oil Recovery

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

Pre-Project Dissertation Report

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



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



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



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



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



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.



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



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)



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)



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



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)



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)



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)



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)



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)



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)



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

http://en.wikipedia.org/wiki/Vitamins

http://en.wikipedia.org/wiki/Surfactants



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)



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.



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.



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.



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)



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)



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.



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



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).



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



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)



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.



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.



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).



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.



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



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



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.



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.



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).



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).



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).



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).



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



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



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



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.



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.



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.



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.



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.



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.



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.



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



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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39. M. Algharaib, Kuwait University, and N. Abu Al-Soof: “Economical Modelling of CO2 Capturing and Storage Projects” SPE 120815, Presented at SPE Saudi Arabia Section Technical Symposium, Al-Khobar, Saudi Arabia, 10-12 May 2008.

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Development Strategies.1st edition, Gulf Professional Publishing, ISBN: 9781856178563. July 30, 2010.

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