Project PreDissertation Report -Enhanced Oil Recovery

2010-2014

Dissertation submitted in partial fullment of the requirement requ irement for the B.Tech B.Tech degree in Petroleum Engineering

By:

School of Petroleum Technology, Technology, Pandit Deendayal Petroleum University, Raisan, Gandhinagar

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

Pre-Project Dissertaon Report

Acknowledgements The work of our B.Tech project tled “Innovaon 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 eciently. eciently. 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

Innovaon in EOR techniques techniqu es

Page | 1


Acknowledgements The work of our B.Tech project tled “Innovaon 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 eciently. eciently. 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


Page | 1


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


Page | 2

Pre-Project Dissertaon Report Petroleum System ........................................... ................................................................. ............................................ .................................... .............. 26 Thermal History.............................................................. .................................................................................... ........................................... .....................26 Source Potential .......................................... ................................................................. ............................................. ....................................... ................. 27 Petroleum plays........................................ 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........................................ 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 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


Page | 3

Pre-Project Dissertaon Report Results ........................................... ................................................................. ............................................ ............................................ ................................ .......... 44 Conclusion ............................................ .................................................................. ............................................ ............................................ ......................... ... 44 Economic analysis of EOR projects ............................................... ..................................................................... .................................... .............. 45 Identification Identification of major costs........................................... ................................................................. ........................................... .....................45 Evaluating Evaluating the NPV and ROR for an EOR project ......................................... ....................................................... .............. 46 EOR Project Risks Risks ......................................... ............................................................... ............................................. ........................................ ................. 48 Major Economic Models used ............................................... ..................................................................... .................................... .............. 49 EOR Economic Model: ....................................................... .............................................................................. ........................................ ................. 50 Appendix ........................................... ................................................................. ............................................ ............................................ .................................... .............. 51 References ............................................ .................................................................. ............................................ ............................................ ................................ .......... 53


Page | 4


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

Innovaon in EOR techniques

Page | 5


Introducon In today’s me, Enhanced Oil Recovery (EOR) has become one of the sought aer research arenas in the oil and gas industry. The industry average of 35% recovery eciency for convenonal crude oil results in a large amount of idened oil le behind, despite exisng producon infrastructure. Many EOR techniques are already in pracce around the world but the global energy demands are ever -increasing. This propels innovaons in the exisng EOR schemes as even a meagre increase in producon of oil is highly valued in the industry. This project deals with developing an economically feasible innovaon in any exisng EOR scheme for the petroliferous basin in Gujarat i.e. the Cambay Basin. The focus is on major elds in the Cambay Basin, namely Balol & Santhal, Viraj, Sanand & Jhalora. This report entails a detailed study of the elds and the current EOR schemes in use. An innovaon in EOR technique can only be designed with proper background knowledge of the ongoing process and its limitaons.


Page | 6


Oil Recovery There are three phases of recovering as below and in gure 1:

F IGURE 1 OIL RECOVERY CLASSIFICATIONS (L AKE , 1989)

Primary recovery Primary Recovery Mechanism occurs when wells produce because of natural energy from expansion of gas and water within the producing formaon, which pushes uids into the well bore and lis them to the surface.

Secondary recovery It occurs as arcial energy is applied to inject uids into the well bore and li uids to the well bore. This may be accomplished by injecng gas down a hole, installing a subsurface pump, or injecng gas or water into the formaon itself. Secondary recovery is done when well, reservoir, facility, and economic condions permit.

Terary recovery (EOR) EOR occurs when means of increasing uid mobility within the reservoir are introduced in addion to secondary techniques. This may be accomplished by introducing addional heat into the formaon to lower the viscosity (thin the oil) and improve its ability to ow to the well bore. Heat may be introduced by either injecng steam in a steam ood or injecng oxygen to enable the ignion and combuson of oil within the reservoir in a re ood . (Speight, 2009) During primary recovery, the natural pressure of the reservoir or gravity drive oil into the well bore, and arcial li techniques (such as pumps) bring the oil to the surface. Natural


Page | 7

Pre-Project Dissertaon Report energy sources include soluon gas drive, gas cap drive, natural water drive, uid 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 eld’s producve life, generally injecng water or gas to displace oil and drive it to a producon well bore, result in the recovery of an addional 20-40% of the original oil in place. In this phase, reservoir’s natural energy is augmented through injecon. Gas injecon, is either into a gas cap for pressure maintenance and gas cap expansion or into oil -column wells to displace oil immiscibly according to relave permeability and volumetric sweep out consideraons. Gas processes based on other mechanisms such as oil swelling, oil viscosity reducon, or favourable phase behaviour, are considered as EOR processes. Terary 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 inducedenergy methods of primary and secondary recovery. It is started before secondary recovery techniques are no longer enough to sustain producon. 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 heang the oil. In chemical EOR, the injected uids interact with the reservoir rocks/oil system to create condion favourable for oil recovery. These interacons might result in lower IFT’s, oil swelling, oil viscosity reducon, weability modicaon or favourable phase behaviour. (Don W. Green, 1998)

IOR vs. EOR EOR is a broader idea that refers to the injecon of uids 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 terary recovery. Thus EOR can be implemented as a terary process if it follows a waterooding or an immiscible gas injecon, or it may be a secondary process if it follows primary recovery directly. Nevertheless, many EOR recovery applicaons are implemented aer waterooding. The term Improved Oil Recovery ( IOR) techniques refers to the applicaon of any EOR operaon or any other advanced oil recovery technique that is implemented during any type of ongoing oil recovery process. Examples of IOR applicaons are any conformance improvement technique that is applied during any type of ongoing oil recovery operaons. Other examples of IOR applicaons are: hydraulic fracturing, scale -inhibion treatments, acid -smulaon procedures, inll drilling, and the use of horizontal wells. (Romero -Zerón)


Page | 8


Enhanced Oil Recovery Techniques Gas Injecon Gas processes target the light and medium gravity crude oils by lowering the interfacial tension between the injected uid and the crude oil to minimize the trapping of oil in the rock pores by capillary or surface forces. The important strategy related quesons in the design of gas injecon projects are:      

Should it be a completely miscible (on rst contact or mulple contacts) or near miscible or immiscible project? How should the mobility of the displacement be controlled? Does the injecon of a miscible solvent aect reservoir weability? If so, how can it be accounted for in the design? What are the eects of reservoir weability on waterood and miscible ood performance? What are the eects of rock heterogeneity on displacement mechanisms and miscible ood performance? What are the eects of changing reservoir pressure on minimum miscibility pressure, and injected solvent gas composion? How do we determine miscibility?

Miscible Gas Injecon Oil recoveries for gas injecon processes are usually greatest when the process is operated under condions where the gas can become miscible with the reservoir oil. The primary objecve of miscible gas injecon is to improve local displacement eciency and reduce residual oil saturaon below the levels typically obtained by water ooding. Examples of miscible gas injectant are CO2 or N2 at suciently high pressure, dry gas enriched with sucient quanes of LPG components, and sour or acid gases containing H2S. The condions under which gas becomes miscible with oil (MMP) are most commonly determined in the laboratory using slim -tube experiments. Phase behavior measurements, in combinaon with composional simulaon, can also be used to determine miscibility condions. (G.F. Teletzke, 2005)

Immiscible Gas Injecon The key to successful gas ooding 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 ows easily to the producon well. Flow is ideally piston like in that whatever gas volume is injected displaces an approximately equal volume of reservoir uid. Unfortunately, miscibility is not always possible and reservoir heterogeneies can cause gas to cycle through one or more layers, which results in poor recovery eciency. A proper gas ood design will consider both the displacement and sweep eciency that result and the protability of that process. (Johns, 2013)


Page | 9


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 eciency of the injected uid by either one or a combinaon of the following processes: (1) Mobility control by adding polymers to reduce the mobility of the injected water, and (2) Interfacial tension (IFT) reducon by using surfactants, and/or alkalis. Chemical EOR faces signicant challenges, especially in light oil reservoirs. One of the reasons is the availability, or lack of, compable chemicals in high temperature and high salinity environments. There are three general methods in chemical ooding technology.   

Alkaline Flooding Micellar/Polymer Flooding Alkali, Surfactant, Polymer(ASP) Flooding

Alkaline Flooding – Weability Alteraon In this method, the change in weability characteriscs is responsible for improved recovery and is parcularly 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 ood water by a factor of several hundred. Under appropriate condions of salinity, pH and temperature, the weability of the porous media becomes more favourable to enhanced producon. The matrix material weability is always changed from strongly water -wet to preferenally oil -wet as the ood front passed a point which is caused by adsorpon of soap molecules (formed by the interracial reacon) onto the solid surface. (C.E. Cooke, Jr. et al.) When the proper alkaline water and acidic oils ow through the porous media, an oil -water emulsion is formed. The ow properes 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 eecvely displaces the oil from the pores. The various mechanisms acve at the front where the alkaline water displaces the crude oil are:    

A drasc reducon of oil/water interfacial tension; Weng of the porous media; Formaon of water drops within the oil phase; Drainage of oil from the volume between the alkaline water drops to produce an emulsion containing very lile oil.

The compability of a given alkali is of utmost importance. The reacon of the alkali with the high molecular weight acids is required for altering the weability. Acidic gases, such as H 2S and CO2, are tolerable only at lower concentraons, because their reacon products (Na 2S and Na2CO3) with excess NaOH may sll be suciently alkaline. Bivalent ions present in


Page | 10

Pre-Project Dissertaon Report water could deplete an alkali slug by the formaon of insoluble hydroxides. This can be avoided by placing a fresh water or sodium chloride buer before injecng the alkali. Gypsum or anhydrides present in substanal quanes would render a slug ineecve due to the dissoluon of CaSO 4 and the precipitaon of calcium hydroxide. Clays with high -ionexchange capabilies would also render the sodium hydroxide slug ineecve by exchanging hydrogen for sodium. (Narendra Gangoli, 1977) When oil containing organic acids is ooded with alkaline water, the result can be a high oil recovery eciency, provided a bank of viscous oil -in-water emulsion forms in situ. The amount of addional 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 nes in the porous medium. (C.E.Cooke, 1974)

F IGURE 2 EFFECT OF FLOOD WATER SALINITY ON RECOVERY OF SYNTHETIC ACIDIC OI L BY ALKALINE WATERFLOODING (C.E.C OOKE, 1974)


Page | 11


Micellar/Polymer Flooding Micellar-polymer ooding is based on the injecon 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 ooding is also known as Micellar, micro emulsion, surfactant, low -tension, soluble -oil, and chemical ooding. The dierences are in the chemical composion and the volume of the primary slug injected. For instance, for a high surfactant concentraon system, the size of the slug is oen 5%-15% pore volumes (PV), and for low surfactant concentraons, the slug size ranges from 15%-50% PV. The surfactant slug is followed by polymer -thickened water. The concentraon of polymer ranges from 500 mg/L to 2,000 mg/L. The volume of the polymer soluon 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 ows as connuous 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 condions (temperature, brine salinity and hardness). (Romero -Zerón)

F IGURE 3 S CHEMATIC ILLUSTRATION OF POLYMER FLOODING SEQUENCE ( DRAWING BY JOE LINDLEY , U.S. D EPARTMENT OF E NERGY , B ARTLESVILLE , OKLA .) (L AKE , 1989)


Page | 12


Alkali, Surfactant, Polymer Flooding In the Alkaline Surfactant Polymer (ASP) process, a very low concentraon of the surfactant is used to achieve ultra -low interfacial tension between the trapped oil and the injecon uid/formaon water. The ultra -low interfacial tension also allows the alkali present in the injecon uid to penetrate deeply into the formaon and contact the trapped oil globules. The alkali then reacts with the acidic components in the crude oil to form addional surfactant in -situ, thus, connuously providing ultra -low interfacial tension and freeing the trapped oil. In the ASP Process, polymer is used to increase the viscosity of the injecon uid, to minimize channelling, and provide mobility control. ASP ooding combines interfacial tension -reducing chemicals (alkali and surfactant) with a mobility control chemical (polymer). Alkali and surfactant both minimize capillary forces that trap waterood residual oil, while the polymer improves reservoir contact and ood eciency. (Khaled Abdalla Elraies, 2012)

F IGURE 4 R ESIDUAL OIL UNDER SEM (P OLYMER FLOODING AND ASP FLOODING IN D AQING OILFIELD )


Page | 13


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 relavely shallow (less than 3,000 feet) very viscous heavy oil (generally dened 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 ow unless diluted with a solvent or heated. Heat is applied to the crude to:    

reduce the viscosity of the crude, acvate a soluon gas drive in some instances, result in thermal expansion of the oil and hence increased relave permeability, Create disllaon and, in some cases, thermal cracking of the oil. (Kok, 2008)

Thermal methods are generally of three types:

Cyclic Steam Injecon (Steam Smulaon, Steam Soak or Hu and Pu): 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. Aer injecon of short period, the well is placed back on producon. This is essenally a well bore smulaon technique, each well responding independently. (Kok, 2008)

F IGURE 5 S TEAM INJECTION PROCESS (NIPER, OKLAHOMA)


Page | 14


Steam Flooding (Steam drive, Connuous Steam Injecon): The steam ooding involves the connuous injecon of about 80% quality steam into reservoir to transfer heart to oil bearing formaon, which reduces oil viscosity and increases the mobility rao of oil and displaces crude towards producing wells. (Abdus Saer, 1994)

Steam recovers crude by:   

Heang the crude oil and reducing the viscosity. Thermal expansion of oil and steam disllaon. Supplying pressure to drive oil to producing well.

F IGURE 6 S TEAM FLOOD DISPLACING OIL FROM RESERVOIR (E&P MAGAZINE , AUG 29, 2007)


Page | 15


In-Situ Combuson (Fire-ood): This process involves starng a re in the reservoir and injecng 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 uid to ow more readily from the formaon into the producon well. Another phenomenon, thermal and catalyc cracking, that occurs during this process helps in up gradaon of crude oil. (Abdus Saer, 1994)

F IGURE 7 IN-SITU C OMBUSTION PROCESS (NIPER, OKLAHOMA )


Page | 16


Microbial Enhanced Oil Recovery Microbial Enhanced Oil Recovery (MEOR) is a biological based technology consisng in manipulang funcon or structure, or both, of microbial environments exisng in oil reservoirs. MEOR is a terary oil extracon technology allowing the paral 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 Reducon of Interfacial tension, Selecve plugging of the most permeable zones and Reducon of oil viscosity. Bacterial growth occurs at exponenal rate; therefore bio surfactants are rapidly produced. The acvity of bio surfactants compare favourably with the acvity of chemically synthesized surfactants. MEOR smulaon can be chemically promoted by injecng electron acceptors such as nitrate; easy fermentable molasses, vitamins or surfactants. Alternavely, MEOR is promoted by injecng exogenous microbes, which may be adapted to oil reservoir condions 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 producon of desired product at the surface and the subsequent injecon into a reservoir; Direct injecon of microorganism into a reservoir and in -situ generaon of desirable product.

T ABLE 1 B IO -PRODUCTS AND THEIR APPLICATIONS TO E NHANCED O IL R ECOVERY (J ANSHEKAR , 1985):

Bio-product Acids

Effects Modicaon of reservoir rock

Improvement of porosity and permeability Biomass

Reacon with calcareous rocks & CO 2 producon Selecve or non-selecve plugging Emulsicaon through adherence to hydrocarbons Modicaon of solid surfaces Degradaon & alteraon of oil Reducon of oil viscosity and oil pour point

Gases

Desulfurizaon of oil Reservoir re pressurizaon Oil swelling Viscosity reducon Increase of permeability of carbonate rocks by CO 2


due

to

solubilisaon

Page | 17

Pre-Project Dissertaon Report Solvents Dissolving of oil Surface-active Lowering of interfacial tension Agents Polymers

Emulsification Mobility control Selective plugging

MEOR smulaon can be carried out by two methods

Hu and Pu Method In hu and pu method water, nutrients and microbes injected and then well shut -in and give me to microbes to grow. During their growth, they use nutrients and produce surfactant, polymer, alcohols and CO2. Then producon can be started from same well. While in Microbial Flooding the nutrients and microorganisms are injected from injecon well and producon is obtained from producon well.

F IGURE 8 HUFF AND PUFF METHOD (M. M. SCHUMCHER , 1980):

Schemac showing the migraon of cells and the synthesis of metabolic products around the wellbore following inoculaon and closing of injecon well (Hu stage)


Schemac showing the producon of oil at the end of the incubaon period, when the well is reopened (Pu stage)

Page | 18


Microbial Flooding

F IGURE 9 M ICROBIAL F LOODING (M. M. SCHUMCHER , 1980)

Economics of the MEOR smulaon:     

Microbes and nutrients are relavely cheap materials. Cost is independent of oil prices. Implementaon needs minor modicaons to eld facilies. Economically aracve for marginal producing wells. The total cost of incremental oil producon from MEOR is only 2 – 3 $/bbl.

Advantages of MEOR:     

Easy applicaon. Low energy input requirement for microbes to produce MEOR agents. More ecient than other EOR methods when applied to carbonate oil reservoirs. Microbial acvity increases with microbial growth. This is opposite to the case of other EOR addives in me 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 liming its applicability in oshore plaorms due to logiscal problems Exogenous microbes require facilies for their culvaon. Indigenous microbes need a standardized framework for evaluang microbial acvity, e.g. specialized coring and sampling techniques.


Page | 19


Screening criteria Success of a parcular 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 parcular reservoir thus, becomes challenging. It is best done based on a detailed study of each specic eld. Evaluaon is carried out at each stage to increase the chances of an EOR technique achieving technical and economic success. (Terry, 2001) The applicaon of EOR processes are both reservoir -specic and reservoir uid-specic. This literally means that each EOR process must be specically evaluated before it can be applied to a reservoir. The evaluaon process is typically extensive and may include laboratory work, geologic and reservoir modeling, economic analyses, and in many cases eld trial in the form of a pilot test. The dierent selecon criteria presented are meant to serve as the rst -pass screening procedures that compare the candidate reservoir with other reservoirs that have been produced with an EOR process. They cannot replace the rigorous evaluaon procedure that each EOR process must undergo before it is actually implemented in the eld. The rst step in the evaluaon 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 eld successes and failures to provide a posive 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 properes of the uids and combinaons of uids, including that of crude oil and formaon water needs to be studied for the chosen technique. Aer the eld history is evaluated, updated stac and dynamic reservoir models can be developed for analyzing the EOR potenal of the reservoir. The task of screening an EOR method has become easier and more ecient because of the increase in the no. of iteraons that can be done. A number of models, correlaons and computer models are available in the market for this purpose. Operators compare expected supply costs and project economics to the scenario when the producon is connued without any EOR technique. When a eld 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 simulaon study indicates that the project is meeng company’s technical and nancial requirements, then it can be applied to the eld. These screening criteria (aached in Appendix) are only guidelines. If a parcular reservoir– crude oil applicaon appears to be on a borderline between two dierent 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.


Page | 20

Pre-Project Dissertaon Report Taber et al. (1976) came up with a set of screening criteria that should guide petroleum engineers on the parcular choice of EOR method to use. Since then, a no. of screening criteria have been proposed by dierent authors, as a result of analyzing elds in which parcular methods have been applied and found successful.


Page | 21


Geology of the Cambay Basin Geographic Locaon of the basin The Cambay ri Basin, a rich Petroleum Province of India, is a narrow, elongated ri graben, extending from Surat in the south to Sanchor in the north. In the north, the basin narrows, but tectonically connues beyond Sanchor to pass into the Barmer Basin of Rajasthan. On the southern side, the basin merges with the Bombay Oshore Basin in the Arabian Sea. Basin is roughly limited by latudes 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)

F IGURE 10 GEOGRAPHY OF THE CAMBAY BASIN (DGH )

Tectonic history The Cambay Basin riing took place around 65 Ma, concomitant with the erupon of Deccan volcano during ri-dri transion phase of the Indian plate. The ri iniaon is characterized by basin bounding extensional fault (listric / planar normal fault) facilitang the inial basin subsidence with the up liment of the basin margin of ri shoulders. The basin is divided into dierent tectonic blocks linked with each other by transfer fault system (gure 11). The ve tectonic blocks in the basin are: 1. 2. 3. 4. 5.

Sanchor–Patan Mehsana–Ahmedabad Tarapur–Cambay Jambusar–Broach Narmada – Tap F IGURE 11 S CHEMATIC OF TECTONIC BLOCKS OF CAMBAY RIFT BASIN SEPERATED BY TRANSFER FAULTS (MADAN MOHAN, 1995)


Page | 22


Evoluon of Basin The structural evoluon of the basin can be categorized in three phases: 1. Syn-ri phase 2. Post-ri phase 3. Late post-ri phase During the syn-ri phase, the basin tends to be of asymmetric nature and it characterized by inter basinal highs and lows (gure 12). Reacvaon of oblique faults and basinal uplis resulted in Devla -Malpur upli (Broah -Jambusar block), Kalol upli, Nawagam -Dholka high (Ahmedabad block), Sanand -Jhalora upli (Mehsana block) and Wayad and Wansa highs in

F IGURE 12 GEOLOGICAL CROSS SECTION ALONG CAMBAY R IFT B ASIN (M ADAN M OHAN , 1995)

Patan block. The basin subsidence connued along the extensional faults (Mohan M, 1995). The trappean fault acvity ceases to a greater extent during post ri phase (Thermal Subsidence stage) and the subsidence connued due to rapid crustal cooling and sedimentary load deposited by principal uvial systems. Late post-ri phase is characterized by reverse separaon along fault plane resulng in structural inversion within the basin. It may be menoned that this type of structural readjustment within ri tectonics can be aributed to thermal contracon and isostac compensaon of the sediments. The Narmada geofracture was reacvated during post -Miocene me down throwing Broah Jambusar block considerably. The phases of basin evoluon through syn -ri, post -ri and


Page | 23

Pre-Project Dissertaon Report structural inversion stages broadly conrm the tectonic cycles such as formave, negave, oscillatory and posive put forth by Raju (1968).

Generalized Stragraphy 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 t hroughout 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.


Page | 24

Pre-Project Dissertaon Report 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.

F IGURE 13 GENERALIZED S TRATIGRAPHY OF THE CAMBAY BASIN


Page | 25


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 elds, is also inferred to be an important hydrocarbon source rock. The total organic carbon and maturaon studies suggest that shales of the Ankleshwar/Kalol formaons also are organically rich, thermally mature and have generated oil and gas in commercial quanes. The same is true for the Tarapur Shale. Shales within the Miocene secon 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 Formaon. These consist of sand size basalt fragments. Besides this, localized sandstone reservoirs within the Cambay Shale as in the Unawa, Linch, Mandhali, Mehsana, Sobhasan, elds, etc are also present. Trap Rock: The most signicant factor that controlled the accumulaon of hydrocarbons in the Olpad Formaon is the favorable lithological change with structural support and short distance migraon. 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 migraon & Trap formaon: The peak of oil generaon and migraon is understood to have taken place during Early to Middle Miocene. (DGH)

Thermal History The thermal history of the basin is characterized by inial high heat ow followed by cooling as the ri aborted. The average heat ow 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 ri tectonics, the high heat ow zone can be aributed to lithospheric thinning. Interesngly, this part of the basin is characterized by high gravity anomalies, Bouger anomaly +37 mgals. (Madan Mohan, 1995).


Page | 26


Source Potenal Favorable thermal history with high heat ows followed by cooling eect has facilitated for generaon and preservaon of hydrocarbon in the Cambay Basin. The syn -ri organic rich Cambay Shale constute the principle source facies of kerogen type II/III and total organic carbon (TOC) is higher in the northern basin (gure 14), whereas maturity level is higher in the south. Early oil generaon 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 migraon. At places, low maturity (VR o =0.4-0.5) oil in Mehsana sub -block is aributed to oil generaon from coal. The source potenal 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 generaon took place since Middle Eocene and basin wide oil migraon took place in Early Miocene me. (Madan Mohan, 1995).


F IGURE 14 TOTAL O RGANIC CARBON (TOC) CONTOUR IN CAMBAY S HALE

Page | 27


Petroleum plays Structural Highs and fault closures & Stragraphic traps (pinchouts / wedgeouts, lencular sands, oolic sands, weathered trap) in Paleocene to Miocene sequences have been proved as important plays of Cambay Basin.

1. Paleocene – Early Eocene Play: Formaons: Olpad Formaon/ Lower Cambay Shale. Reservoir Rocks: Sand size basalt fragments & localized sandstone. Unconformies within the Cambay Shale and between the Olpad Formaon and the Cambay Shale have played a posive role in the generaon of secondary porosies. The Olpad Formaon is characterized by the development of piedmont deposits against fault scarps and fan delta complexes.

2. Middle Eocene Play: Formaons: Upper Tharad Formaon Reservoir Rocks: In Southern part, Hazad delta sands of mid to Late Eocene & in the Northern part the deltaic sequence is made up of alternaons 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: Formaons: Tarapur Shale, Dadhar Formaon. Reservoir Rocks: This sequence is observed to possess good reservoir facies in the enre Gulf of Cambay. North of the Mahi River, a thick deltaic sequence, developed during Oligo–Miocene, has prograded upto south Tap area.

4. Miocene Play: Formaons: Deodar: Formaon (LR. Miocene), Dhima Formaon (Mid Miocene), Antrol Formaon (Upper Miocene) The Mahi River delta sequence extends further westward to Cambay area where Miocene rocks are hydrocarbon bearing. (DGH)


Page | 28


Case Study I: Enhanced Oil Recovery by In -Situ Combuson (ISC) Technique in Balol and Santhal Fields, Mehsana The northern part of Cambay basin has a belt of heavy oil elds. Santhal and Balol are two such major elds located in the Mehsana block, having API gravies 15 o-18o. In-situ combuson technique has been implemented in these elds to enhance the recovery of oil.

F IGURE 15 B ALOL AND SANTHAL F IELDS IN CAMBAY BASIN (G.K P ANCHANAN , 2006)

Background Balol eld was discovered in 1970 and put on producon in 1985 through convenonal cased vercal wells drilled at 22 acre spacing. Arcial lis like Sucker rod pumps and screw pumps were used for cold producon 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 injecon and ISC were the two opons considered. But, steam injecon could not be implemented owing to depth of 1000m, presence of strong water drive and a pay thickness of 5m. This le ISC as the choice for pilot tesng.

Geology The Balol eld 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 formaon and Lower Pay formaon from top to boom. These pay sands were deposited during the early and middle Eocene period and represent the characterisc regressive cycle intervening between two major transgressive shale deposits. Kalol formaon accounts for 95% of the eld OOIP.


Page | 29

Pre-Project Dissertaon Report K-1 is the major pay of Kalol formaon and is spread throughout the eld. (Har Sharad Dayal et.al, 2010) Santhal eld has N -S trending anclinal 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 & uid properes K-, in the Balol eld, 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/cm 2. The viscosity varies between 150 to 1000 cP throughout the eld. Oil saturaon of K -1 sand is 77%. The soluon GOR is 20 -26(v/v) and the inial FVF is 1.05. In the Santhal eld, 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 Chaopadhyay et.al, 2004). The oil in Santhal eld contains around 9 -9.5 % asphaltenes and 10-13% resins.

ISC implementaon In Balol eld, the process was tested in the laboratory and in the eld on a pilot & semi commercial scale prior to commercializaon in 1997. The commercializaon process was done in two phases - Phase I and Phase II and it was based on the Nelson & Mc Neil approach. In Santhal eld, the ISC process was executed in KS -1 reservoir adopng an inverted 5 spot injecon-producon paern in the north western part. But, during commercial applicaon, it was changed to up -dip line drive (S.K Chaopadhyay et.al, 2004).

ISC process Both in Balol and Santhal elds arcial ignion was carried out using Gas Burner as opposed to spontaneous combuson. This is because with arcial ignion, high vercal sweep can be achieved. Also, the chances of oil saturaon close to the wellbore become less. So, if there is unplanned stoppage of air injecon, the chances of backow of ue gases into the injecon wells is minimised.


Page | 30

Pre-Project Dissertaon Report Crestal line drive air injecon was formulated taking the assistance of gravity, in both the elds. This helps in nullifying the heterogeneity and pertains to less handling of ue gases as part of it remains as gap cap. In order to enhance sweep eciency, wells in both the elds are subjected to wet combuson, which involves injecon of pre -esmated volume of air in a cycle of six days followed by one -day water (S.K Chaopadhyay et.al, 2004).

Producon performance Balol eld: In phase 1 of the ISC implementaon, pre -iniaon cold oil producon was about 60 m 3/d with water cut of 80%. With air injecon, the oil producon increased to 260 m 3/d with reducon of average water cut from 82% to about 40% (Figure 16).

F IGURE 16 C ROSS PLOT OF A IR R ATE & OIL PRODUCTION RATE IN PHASE I (H AR S HARAD DAYAL ET .AL , 2010)

In Phase II oil producon rate increased up to 500 m 3/d. Air injecon peaked in 2004 at the rate of 0.5 MM S m 3/d. Meanwhile, the oil producon has shown a linear increase with air injecon rate (Figure 17). Up to 2010, 960 MM Sm 3 of air has been injected, yielding 0.63 MM m3 of incremental oil (Har Sharad Dayal et.al, 2010).

F IGURE 17 CROSS PLOT OF AIR RATE & OIL PRODUCTION RATE IN PHASE II (HAR SHARAD DAYAL ET.AL, 2010).


Page | 31

Pre-Project Dissertaon Report In Santhal eld, 23 injectors have been drilled and they have improved the producon of oil by around 540 tons/day over the base producon in a me limit of 5 years (S.K Chaopadhyay et.al, 2004). In fact, many wells which were operang under Arcial li prior to ISP process, are now operang under self -ow mechanism.

Issues  



Rupture of Downhole -equipment at high temperature and high pressure: 2 incidents of bursng of 3rd stage air compressors had taken place in Santhal eld. Flow back of ue gases: Breakthrough of ue gases along with air have been noced in the Balol eld in 2006, due to annular leakage in one injector well. Drilling of new injector wells with right casing policy, cementaon and metallurgy for tubing is required. Highly costly technique. Combuson started at the injector results in hot produced uids that oen contain unreacted oxygen. These condions require special, high -cost tubular to protect against high temperatures and corrosion. More oxygen is required to propagate the front compared to forward combuson, thus increasing the major cost of operang an in situ combuson project.


Page | 32


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)

F IGURE 18 T ECTONIC MAP OF CAMBAY B ASIN (D EBASHIS ET AL ., 2008)

Reservoir Characteriscs 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


Page | 33

Pre-Project Dissertaon Report 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: T ABLE 2 R ESERVOIR PARAMETERS OF JHALORA K- IV SAND (J AIN , D HAWAN , & MISHRA , 2012)

S.No. Parameters

Value

1

Average Depth, m (MSL)

1265

2

Average pay thickness, m

7-9

3

Temperature, OC

82

4

Inial Reservoir Pressure, kg/cm 2

140

5

Current Reservoir Pressure, kg/cm 2 ~127

6

Saturaon pressure, kg/cm 2

99

7

Inial Oil Saturaon 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

Formaon Water Salinity(mg/l)

11291

The mature stage of the eld with heterogeneous reservoir and unfavorable uid characteriscs makes it an ideal choice for applicaon of chemical process an EOR technique to enhance recovery. Based on properes of the K -IV sand and screening criteria (aached in Appendix) in the table above, ASP was chosen as the EOR technique to be applied in the eld. Before Field implementaon, Extensive lab and Simulaon studies were done by Instute of Reservoir Studies (IRS) -ONGC, Ahmedabad. Results of these studies are summarized in the following points:  

 

envisage incremental displacement eciency of about 23% of OIIP Pilot design envisage injecon 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 buer (three slugs of 0.1 PV each with polymer concentraons 1200, 800 and 400 ppm) followed by 0.4 PV chase water ASP injecon rate of 150m 3 /day was recommended Inverted 5-spot paern pilot was designed


Page | 34


Field Implementaon In view of heterogeneous reservoir and unfavorable uid characteriscs, polymer gel based prole modicaon job was carried in the ASP pilot injecon well JH #I prior to commissioning of ASP pilot. Aer that pre -ush of 2% NaCl was injected followed by 16 m 3 of tracer (Ammonium Thiocyanate) injecon. ASP pilot project started funconing from 07th February 2010.

F IGURE 19 SCHEMATIC MAP OF JHALORA ASP PILOT AREA (J AIN , D HAWAN , & MISHRA , 2012)

Where,

JH# I: Injecon well JH# A, B, C and D: Production wells JH# E and F: Offset monitoring wells

Producon Performance of ASP pilot producers Combined performance of six pilot producers in terms of oil rate and water cut is given in (Figure 20). Reducon in water cut in all the pilot producing wells was observed since start of the ASP injecon 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 me. Cumulave oil gain ll Oct’ 2011 is about 47000 barrels.


Page | 35


F IGURE 20 C OMBINED PERFORMANCE OF SIX JHALORA ASP P ILOT PRODUCERS (J AIN , D HAWAN, & MISHRA , 2012)

Conclusion and Further Plan 

 

Inial performance of ASP pilot producers is very encouraging. Reducon in water cut and increase in oil rate is observed in pilot producers. ASP performance is as per predicon. Water soening plant is needed to control high turbidity. Simulaon study is in progress for possible pilot expansion.


Page | 36


Case Study III: Enhanced Oil Recovery by Polymer Flooding Technique in Sanand Field Background Sanand is the only eld in India where eld scale polymer ooding is going on for the last twelve years. The eld was discovered in 1962 and commercial producon commenced from 1969. Oil viscosity of 20 cP led to adverse mobility rao which resulted in cusping of water in structurally higher wells. Hence polymer ood was considered the best opon for improving mobility rao of oil and overall areal and volumetric sweep eciency. KS -III sand is the major hydrocarbon bearing sand in the eld with 64% of proved oil -in-place and 95% of total oil producon. (Deep Tiwari, 2008)

General Geology Sanand eld 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 ancline NNW -SSE. Sanand is a mul-layered reservoir in Kalol sands but KS III is the main reservoir, which belongs to Kalol formaon of Eocene age (Deep 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 eecve permeability barriers. The secon is dominated by interbeded sands, silts, shales and coals, interpreted as a combinaon of marine, coastal marsh and deltaic ood plain environment (S.K.Sharma, 1997) .

F IGURE 21 L OCATION MAP OF SANAND F IELD (C HANCHAL D ASS , 2008).

Reservoir and Fluid properes Reservoir properes 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 85 oC (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%.Inial reservoir pressure was 142 Kg/cm2 at 1325 m datum depth which declined to 100 Kg/cm 2. Crude is under saturated with bubble point pressure of 80 Kg/cm 2 (Deep Tiwari, 2008). Mixed drive mechanism is


Page | 37

Pre-Project Dissertaon Report present with a gas cap support from western ank and a weak aquifer support from eastern ank.

Field Implementaon of Polymer EOR Technique The producon from Sanand Horizon -III started in 1969. Main problems encountered in the eld during the course of producon were high GOR in Crestal wells, water cut and decline in average reservoir pressure. Simulaon studies indicated a recovery of 14.9% OIP by primary methods. ONGC has implemented a large scale polymer ood project in Sanand oil eld. In April, 1985, an experimental pilot project had started in an area of 141 acres of Sanand Horizon-III. Polyacrylamide polymer of concentraon 400 ppm and 15 % pore volume slug size was chosen for eld injecon on the basis of laboratory experiment. As evident from gure, the paern was an asymmetrical FIGURE 22 PILOT WELLS AND EXPANDED WELLS (M AHENDRA P RATAP , 1997). inverted ve spot with 4 producers, 1 injector and 1 monitoring well. The scheme comprised dierent stages which included:

PILOT PHASE

A) Pre-ushing of the reservoir with tube well water B) Injecon of polymerized water of dierent concentraon C) Injecon of chase water Average injecon and producon rates of the pilot wells were opmised for uniform and radial movement of ood front. Before the polymer injecon, KI of concentraon 250 ppm was added as a tracer with rst batch of pre -ush water (S.K.Sharma, 1997). Expanded Pilot Phase(EPP): On successful pilot compleon, the expanded pilot phase

commenced in Feb. 1993. Its size was approximately 338 acres and this phase had four inverted 5 spot paerns with 9 producers and 4 injectors (Mahendra Pratap, 1997) . Field -wide Commercial Applicaon: Total area

covered in the beginning was 1039 acres with 32 producers and 16 injectors. It was designed on the basis of simulaon studies (Mahendra Pratap, 1997). F IGURE 23 WELLS IN COMMERCIALISATION AREA (M AHENDRA PRATAP, 1997) .


Page | 38


Performance Monitoring The main objecve of polymer injecon is to improve oil recovery from the eld with reduced water cut. So maintenance of injecon polymer quality and quanty is vital for the success of polymer ood project. The parameters that were selected for the monitoring purpose included salinity determinaon of the produced water, tracer concentraon; water cut data and polymer concentraon. PLT study, Pressure Fall O study and Pressure Build -up tests, Temperature survey and Flow meter survey are also carried out regularly. The producon and the injecon data are connuously collected and monitored for the idencaon of the various problems and implementaon of the correcve measures. Echometer surveys are conducted periodically to measure uid level and reservoir pressure (Mahendra Pratap, 1997). Monitoring also includes checking quality of injected water for chemical, mechanical and bacteriological degradaon by measuring turbidity, dissolved oxygen, iron content, salinity and pH factor both at polymer tank and injecon lines. Physical cleaning and disinfecon of polymer tanks and owlines, proper removal of dissolved oxygen by oxygen scavengers, biocide dosing to reduce bacterial eect are some of the steps taken from me to me. Injecvity tests are conducted in polymer/chase water injectors from me to me and correcve measures are taken (Deep Tiwari, 2008).

Producon Performance The results before and during the polymer injecon of the pilot phase are shown in gure. It is evident that there is prole improvement as a result of polymer injecon which indicates that polymer had a benecial eect on injecon well. Change in resistance factor (rao 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 concentraon. Producon response to polymer injecon during EPP was also encouraging (Mahendra Pratap, 1997). In April 2008, the sand has produced oil at rate of 232m 3/d with 68% water cut from 44 producers. A total of 508 m3/d of polymer soluon had been injected through 9 wells along with 683 m3/d of chase water through 9 wells (Deep Tiwari, 2008).

F IGURE 24 PERFORMANCE OF EXPANDED P OLYMER P ILOT (M AHENDRA PRATAP, 1997) .


Page | 39


F IGURE 25 PERFORMANCE OF SANAND POLYMER F LOOD PROJECT (C HANCHAL DASS , 2008).

Field Review Performance review, using reservoir simulaon, has been carried out from me to me and exploitaon strategy has been planned /modied accordingly. Simulaon study of 1984 predicted depleon recovery of 14%. Aer iniaon of polymer injecon, simulaon studies were carried out in a Black oil simulator with polymer opon. Again review was carried out in 2007 to idenfy areas of by -passed oil, suggest in -ll locaons and to assess requirement and eect of polymer injecon. Recovery of 35% is predicted by 2020. Polymer injecon is extended up to 2013 based on 25% of total pore volume injecon (Deep Tiwari, 2008).


Page | 40


Case Study III: Enhanced Oil Recovery by Alkaline Surfactant Technique in Viraj Field The Viraj oil eld lies in Ahmedabad -Mehsana tectonic block of Cambay Basin. The eld was discovered in 1977 and was put on producon in 1980. The applicability of Alkaline -Surfactant Polymer (ASP) ood process in Horizon -IX+X in Viraj eld was established on the basis of laboratory invesgaons in 1992. The results of laboratory displacement studies and performance predicon indicated that ASP ood in Viraj eld could produce incremental oil in the range of 18 -24% of OIIP over water ood. It was, however, believed that the process needs to be evaluated on pilot scale to test the laboratory results under actual eld condions and also to ne tune the process parameters. Accordingly, an ASP pilot was commissioned with four inverted 5–spot paerns in a limited poron (68 acres; 276,831 m 2) in northern part of Viraj eld

F IGURE 26 ASP PILOT LOCATION IN VIRAJ FIELD

Field history Viraj eld was discovered in 1977 with drilling of an exploratory well -Viraj-1. A technological scheme was prepared in 1981. Simulaon studies carried out in 1985 indicated a recovery of 24.6% of OIIP by the year 2001. Main problems encountered in the eld during the course of producon were high water cut, sand -cut and frequent down -hole chocking of perforaons and tubing due to asphalc nature of the crude oil. The eld has been developed with a close spacing of 200 -250 metres and there is lile scope for inll drilling to increase the ulmate recovery. In view of the Petrophysical properes of reservoir and characteriscs of crude oil, ASP ooding emerged as most suitable EOR process for achieving maximum recovery.

Reservoir Descripon The presence of oil and gas in Viraj eld was established in Kalol equivalent pay zones VIII, IX+X, Chhatral member of Kadi formaon 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 eld is a doubly plunging ancline trending NNE -SSW. The southern ank 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


Page | 41

Pre-Project Dissertaon Report good sorted sandstone, siltstone Average depth is 1300 metres and the average pay thickness is 15 metres. T ABLE 3 R ESERVOIR D ESCRIPTION OF V IRAJ F IELD :

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 Inial Res. Pressure (Kg/Cm2) 136 Current Res. Pressure (Kg/Cm2) 126 Drive Mechanism Acve acquirer

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 condions of 136 kg/cm 2 and 81o c was 50 cp. The pour point is 15 oCand 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 inial reservoir pressure i.e. 136 kg/cm2 has marginally declined to 126 kg/cm2 aer a cumulave oil producon of 18.9 % of OIIP. It shows that reservoir is operang under acve water drive. T ABLE 4 CRUDE OIL P ROPERTIES IN V IRAJ:

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 T ABLE 5 CHARACTERISTICS OF SURFACTANT USED IN V IRAJ :

CHARACTERISTICS OF SURFACTANT Name Petroleum Sulphonate (HLA) Nature Anionic Acvity 60% Thermal Stability Stable at 81 oC Solubility Soluble in water & Oil phase CMC value 0.20 wt% IFT between Viraj crude oil & tube well water having 0.20 wt% 0.61 mill dynes / cm Surfactant & 1.5 wt% Sod. carbonate


Page | 42


Field implementaon: Surface Facilies and Operaon. Surface facilies were created for storage of tube well water, storage of Alkali Surfactant and Polymer Soluons mixing the chemicals, injecon of dierent on-line doses and injecon of prepared slugs to injectors. Facilies for handling the produced uids were already exisng in Viraj eld. The injecon plant was designed to minimize the manpower requirement. Plant design parameters included facilies to inject liquid @ 800 m 3/d.

Data Acquision With a view to closely monitor the performance of the pilot, a comprehensive data acquision strategy was formulated. The data acquision programme included:      





Injecon details viz. the actual injecon rate, volume and stabilized injecon pressure for each injector separately. Parameters of the injected uid like concentraon, Turbidity, PH etc. for Pre -ush, ASP slug and mobility buer prepared in each tank. Connuous recording of producon details including producon rate, water cut etc. for each producer separately. Record of consumpon of each chemical on daily basis with a view to plan the acon for procurement of Chemicals in me. As all the wells of the pilot are operang on SRP, echo meter studies are carried out under both dynamic and stac condions at regular intervals. Producon logging was planned for all the injecon wells periodically to get informaon regarding injecon prole near the well bore and also to detect the presence of high permeability streaks, if any. In order to understand the paern of uid ow through the matrix, the presence of tracer is being monitored in the samples collecon from all the pilot and oset producers. Samples from both producon and injectors are also analysed at regular interval for bacterial presence and suitable biocide treatment would be given in case of high bacterial counts.

T ABLE 6 PARAMETERS M ONITORED DURING IMPLEMENTATION :

PARAMETERS MONITORED ASP Slug Mobility Bufer Chase Water

Parameters Concentraon Alkali (Wt %) Surfactant, ppm Polymer, ppm Turbidity, NTU Dissolved O2 ,ppm Iron, ppm Salinity gm/lit pH

1.5 ± 0.01 2000 ± 40 800 ± 20 < 10 < 1.2 < 1.5 5 10-11.5


+ 20 < 10 < 1.2 < 1.5 <3 7.7- 9.0

< 10 < 1.2 < 1.5 <3 7- 8.5

Page | 43


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 m 3/d with an average water cut of 83.5%. Performance of these wells during the rst phase i.e. ASP injecon is encouraging as there is improvement in oil rate from 24.4 m 3/d to 98.23 m 3/d. Average water cut has also reduced from 83.5% to 71.4 %.

Conclusion ASP (Alkaline-Surfactant -Polymer) ooding has shown encouraging results improving recovery over water ood during laboratory studies. Pilot is under way to test the ecacy of the process under actual eld condions and also to ne tune the process parameters. Signicant conclusions of the eorts made so far may be summarized as follows:  



   

Reservoir rock and uid properes were studies in detail before ASP ooding was idened as potenal EOR technique to improve recovery eciency in Viraj eld. Suitable chemicals idened for successfully implemenng ASP pilot in Viraj are: Sodium Carbonate as alkali. o Petroleum Sulphonate as surfactant, and o Parally hydrolyzed Poly acrylamide (PHAA) as Polymer. o Laboratory tests were conducted to: Opmize ASP concentraons o Formulate Injecon Strategies o ASP slug design o Dening mobility buer sequence. o Performance evaluaon during the rst phase of the pilot shows encouraging results in terms of both improvement in oil rate and reducon in Water cut. Indicaon of in -situ emulsion formaon shows the ecacy of ASP ooding during this phase of the pilot. Polymer / Tracer break through needs close monitoring in producing wells to understand the preferenal ood -front movement. Successful eld implementaon requires connuous eorts and close eld monitoring of the pilot to test the eciency and eecveness of ASP ooding as potenal EOR technique.


Page | 44


Economic analysis of EOR projects Identication of major costs Field development expenditures  

Drilling and compleon: Drill sufficient new production wells to provide the required acre spacing; drill sufficient injection wells to provide the injecon paern. 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 me 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.


Page | 45


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 me series of cash ows is dened as the sum of the Present Values (PV) for all the cash ows; whether outgoing or incoming for the project. It is a tool to evaluate the present values of future investments, taking into account inaon as well as the returns expected from the project. An NPV>0 points to a project that will be protable in the future, NPV<0 points to an unprotable project and NPV=0 points to a situaon 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 negave as they will deal with the costs of installing new surface facilies, drilling new injecon wells, cost of chemicals, cost of injecon gas, addional pumping and compression facilies etc. However, once the EOR project has been pilot tested and moves to the full eld applicaon, then one can start expecng posive cash oulows soon. These posive cash oulows will not be directly seen by the user as the chemicals or gas injected will not contribute greatly to it. The real contribuon to the positive cash ows in such cases will be the amount of incremental oil that we will be able to produce. More the sweep efciency more is the amount of extra oil produced and more will be our prots. This will then reect 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=Summaon of cash ows 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 equaon 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 ows.


Page | 46

Pre-Project Dissertaon Report 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 Producon 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) + (FCO 2STR * $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=Cumulave oil producon, STB FWPT=Cumulative water production, STB FICIT= Cumulave CO 2 injecon, ton FIWIT=Cumulave water injecon, STB FCO2STR=Cumulave CO2 stored, ton This above written equation (3) is used for calculating the cash flow for CO 2 Injecon projects.


Page | 47


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. Dierent 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. Polical 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 facilies 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.


Page | 48


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 simulaon 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. 2. 3. 4.

Field parameter sector Fluid injection sector Fluid recovery sector 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 oers EOR modeling opons that allow comprehensive analysis. Most of the modern EOR processes can be modeled using this simulator. It is also developed by Schlumberger.


Page | 49


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, cumulave producon, 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 esmate is displayed as total incremental EOR production and incremental production per year from the time the project was initiated. Cash Inow: Producon of Oil. Cash Oulow: Investment cost, Operang Cost, field development expenditures, equipment expenditures, operating and maintenance cost, injection material costs. The production estimate is matched with investment and operang costs and various rates of return to calculate the required price for the oil.

Financial Assumpons: 







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 : Intangible costs equal to 70% of drilling and completion costs for production o wells and 100% of work over costs are expended in the year incurred. Tangible costs equal to 30% of drilling and completion costs for production o wells, plus 100% of all other well lease, and injection investment costs are expended (through depreciation) based on a unit of production approach.


Page | 50


Appendix e r u t a r e p m e T

l a c i t i r c t o n




F * 0 0 2 <

F * 0 0 2

F * 0 0 2 <

F * 0 0 1 <


h t p e D

t f 0 0 0 6 >

t f 0 0 0 4 >

t f 0 0 5 2 >

t f 0 0 8 1 >

t f 0 0 0 8 <

t f 0 0 0 9 <

t f 0 0 0 9 <

t f 0 0 5 1 1 <

t f 0 0 5 4 <

y t i e l i g b a r a e e v m A r e P





d m 0 2 >

d m 0 1 >

d m 0 2 >

d m 0 5 >

d m 0 0 2 >

s s e n k c i h T t e N

g n i p p i d s s e l n u n i h t

g n i p p i d s s e l n u n i h t

e g n a r e d i w


t f 0 1 >



t f 0 1 >

t f 0 2 >

e p y T n o i t a m r o F

e t a n o b r a c r o e s n d t o o s h t d n e M a s

e t a n o b r a c r o e n o t s d n a s

e t a n o b r a c r o e n o t s d n a s


e n o t s d n a s y l b a r e f e r p

t u b d e r t e f e r a p n o e b n r o a t c s d n a s

n o n ) l i t o i o c t V e a r e j n % u I 0 r t o s 4 a > S P a G l i % O (

n o i t i s o p m o C

7

C 1 C f o % h g i h

% 0 3 >

7

C 2 C f o % h g i h

g n i d o o l f r e t a W d % % e % 5 c 0 0 3 n 3 2 a > > h > n E

7

C 5 C f o % h g i h


% 0 5 >

d o h t e M l d l a o a m e o u r v f l % d e o r i 0 b t e s h 5 a a e T > w

r

% 0 4 >

e r a s e t e a l i d b e a r e m r f e e t r p n i t h g i l


P c 0 0 2 <

P c 0 0 0 5 <

0 0 0 0 0 2 <

0 2 >

0 1 >

8 >

e g n n i i l a d o k o l l A F

n o i t s u b m o C

m a e t S

P c 4 . 0 <

P c 0 1 <

P c 0 1 <

P c 0 0 6 <

P c 0 3 <

r P e c t t 0 e 0 b 1 , < P P c c 0 < 5 0 1 1 < f i

y t i } I v P a r A { G

5 3 >

5 3 >

2 2 >

2 1 >

5 2 >

5 1 >

e u q i n h c e T R O E

e u l f & s n a e g g o r t i n

e l b i c s i m C H

2 O C

s e s a g e l b i s i m m I

t n g r g a i n e i n t c d m d y a o o f r l o l o l o u F P f S

C G N I N E E R C

S R O E R E B A

T J J 7 2

E R U G I

e r a s d i u e l f l c b a i r n i a s g e r o d e m o s

) P c ( y t i s o c s i V


y y t i e t i e s n s n o o o o r t r t o s o s p d p d h n h n g a g a i s i s s h h

e n o t s d n a s

A I R E T I R

c i t s l t a h n p e s n a o p e m m o o c s


F

Page | 51

Pre-Project Dissertaon Report p a c s a G

o N

o N

r e f i u q A

o N

s e s a c w e f n i k a e W

g l n l i e c ) t f a W p ( S

P S A r o f a i r e t i r c g n i n e e r c s f o y r a m m u S

6 . 3 0 4

y a l C

w o L

w o L

y g o l o h t i L

e n o t s d n a S

e n o t s d n a S

0 0 0 1

8 7 1

t ) n e m l a p v ( p i D r ) e m t a p p , w S n D o T i t ( a t y i m r i n o l F a s ) C ° ( r T ) D m ( k ) . c a r f ( o S ) P c ( o µ

y b d e s o p o r P

C 0 6 < r T f i 0 0 0 , 0 2 <

o

0 0 0 , 0 5

C o 0 6 > r T f i 0 0 0 , 0 5 <

3 9 9 7

3 . 3 9 <

0 7 <

3 . 3 9 <

2 5

0 1 >

0 5 >

0 0 1 >

3 7 4

5 4 . 0 >

3 . 0

5 3 . 0 > 0 0 2 <

5 3 <

0 5 1 <

5 3 <

9 . 2 1

2 9 9 1 . l a t e e k a L

) b , a 7 9 9 1 ( l a t e r e b a T

4 0 0 2 . l a t e r a h a B ‐ l A

0 1 0 2 . l a t e n o s k c i D

s t c e j o r p P S A m o r F


) 3 1 0 2 ,

G N E H

S ( P S A R O F A I R E T I R C G N I N E E R C S 7 E L B A T

Page | 52


References 1. Abdus Saer, 1994, Integrated Petroleum Reservoir Management, pg.177 -189

2. An Overview of Santhal Field An EOR Implemented Field of Cambay Basin, Inferred From 3D Seismic: G.K Panchanan, Vinod Kumar, T.K Mukherjee & R.N Bhaacharya, ONGC Mehsana Asset, 2006. 3. Ashok Kumar, Reservoir Nature and Evaluaon 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 Waterooding. 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 Internaonal Conference & Exposion 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. 8. Enhanced Oil Recovery by In -Situ Combuson Process in Santhal Field of Cambay Basin, Mehsana, Gujarat, India -A Case Study: S.K Chaopadhyay, Binay Ram, R.N Bhaacharya and T.K Das, ONGC, Sub -Surface, Mehsana Asset, Mehsana, Gujarat, India,2004, SPE 89451. 9. Enhanced Oil Recovery Informaon, Naonal Instute of Petroleum and Energy Research(NIPER), April 1986 Revised Edion, pg. 20 -30 10. Petroleum. (n.d.). Retrieved November 15, 2013, from hp://pet -oil.blogspot.in/: hp://pet-oil.blogspot.in/2012/03/enhanced-oil-recovery-thermal-recovery.html 11. (n.d.). Retrieved 11 15, 2013, from DGH: hp://www.dghindia.org/7.aspx 12. (n.d.). Retrieved November 15, 2013, from Ministry of Science and Technology (MOST): hp://www.most.gov.mm/techuni/media/PE_05045_2.pdf 13. Enhanced Oil Recovery By In Situ Combuson Environmental Sciences Essay. (n.d.). Retrieved November 15, 2013, from UKEssays: hp://www.ukessays.com/essays/environmental -sciences/enhanced-oil-recovery-byin-situ-combuson-environmental-sciences-essay.php 14. In-Situ Combuson 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 Combuson: Opportunies and Anxiees: Har Sharad Dayal, B.V Bhushan, Sujit Mitra, S.K Sinha and Siddhartha Sur, SPE, ONGC,2010 SPE 126241. 16. Jain, A. K., Dhawan, D., & Mishra, T. (2012). ASP ood Pilot in Jhalora (KIV) - A Case Study. SPE Oil and Gas India Conference. Mumbai: SPE. 17. Lake, Larry W., Enhanced Oil Recovery, Prence Hall, Englewood Clis New Jersey (1989) 18. Madam Mohan, 1995, Cambay Basin – A Promise of Oil and Gas potenal, Journal of the Paleontological society of India. Vol 40, pp. 42 19. Mahendra Pratap: “M.S Gauma: Field Implementaon of Alkaline -Surfactant -Polymer (ASP) Flooding: A maiden eort in India”, SPE 88455, Australia, Oct 2004. 20. Pratap, Mahendra et al.: “Field Implementaon of Polymer EOR Technique -A Successful Experiment in India”, SPE 38872, Texas, October 1997.


Page | 53

Pre-Project Dissertaon Report 21. Raju, A.T.R, 1968. Geologic evoluon of Assam and Cambay Terary Basins of India,

AAPG, 52:2422-2437. 22. S. M. Farouq Ali and S. Thomas: “A realisc Look at Enhanced Oil Recovery” Sciena Iranica 1:219-230 (1994). 23. Sharma, S.K. et al.: “Performance Analysis of Polymer Injecon on Pilot Scale: A Case History”, SPE 38317, California, June 1997. 24. Sheng, J. J. (2013). A Comprehensive Review of Alkaline -Surfactant -Polymer(ASP) Flooding. SPE Western Regional & AAPG Pacic Secon Meeng. California: SPE. 25. Taber, J.J., Marn, F.D., Seright, R.S. “EOR Screening Criteria Revisited”, 1986, Proceedings of the SPE/DOE Tenth Symposium on Improved Oil Recovery, held at Tulsa, Oklahoma, U.S.A, SPE 35385. 26. Tiwari, Deep et al.: “Performance of Polymer Flood in Sanand Field, India -A Case Study”, SPE 114878, Perth, Australia, October 2008. 27. Sen, R., Biotechnology in petroleum recovery: The microbial EOR. Progress in Energy and Combuson Science, 2008. 34(6): p. 714 -724 28. Janshekar H, Microbial enhanced oil recovery processes: J. E. Zajic and E. C. Donaldson (Editors), Microbes and Oil Recovery, 1. Bioresources publicaons, El Paso, Texas, pp. 54-84 (1985) 29. Aladasani A. & Bai B. "Recent Developments and Updated Screening Criteria of Enhanced Oil Recovery Techniques." SPE 130726 presented at the CPS/SPE Internaonal Oil & Gas Conference and Exhibion. Beijing, China, 8 -10 June: Society of Petroleum Engineers, 2010. 1 -24. 30. Polymer ooding and ASP ooding in Daqing Oileld . (n.d.). Retrieved November 14, 2013, from CNPC: hp://www.cnpc.com.cn/resource/english/images1/pdf/Brochure/Polymer%20ood ing%20and%20ASP%20ooding%20in%20Daqing%20Oileld.pdf 31. Khaled Abdalla Elraies, S. A. (2012). A New Strategy for Minimizing Precipitaons during ASP Flooding in Carbonate Reservoirs. World Academy of Science, Engineering and Technology (72), 1527. 32. M. M. Schumcher; Enhanced Recovery of Residual and Heavy Oil; 2nd edion; Noyes Data Corporaon; Park Ridge, New Jersey, USA;1980; pp.32 -64 33. Abdulrazag Y. Zekri: “Economic Evaluaon of Enhanced Oil Recovery” SPE 64727 , Presented at Internaonal Oil and Gas Conference and Exhibion, Beijing, China, 2000. 34. Speight, J. G. (2009). Enhanced Recovery Methods for Heavy Oil and Tar Sands. Gulf Publishing Company. 35. J. Roger Hite, M. Lee Blanton, M. Kuhlman and W. Fair: “Managing Risk in EOR Projects” SPE 152700 presented at The SPE Lan American and Caribbean Petroleum Engineering Conference, Mexico City, Mexico, April 2012. 36. Narendra Gangoli, G. T. (1977, October -December). Enhanced Oil Recovery Techniques- State of the Art Review. Journal of Canadian Petroleum Technology , 16. 37. Romero-Zerón, L. (n.d.). Advances in Enhanced Oil Recovery Processes. Retrieved November 14, 2013, from www.intechopen.com: hp://cdn.intechopen.com/pdfs/37036/InTechadvances_in_enhanced_oil_recovery_ processes.pdf 38. Lake, L. W. (1989). Enhanced Oil Recovery. Prence Hall Incorporated.


Page | 54

Pre-Project Dissertaon Report 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 Secon Technical Symposium, Al -Khobar, Saudi Arabia, 10 -12 May 2008. 40. Don W. Green, G. P. (1998). Enhanced Oil Recovery. Richardson, Texas: SPE. 41. Vladimir Alvarado, Eduardo Manrique. ―Enhanced Oil Recovery: Field Planning and Development Strategies.1 st edion, Gulf Professional Publishing, ISBN: 9781856178563. July 30, 2010.


Page | 55

Project PreDissertation Report -Enhanced Oil Recovery

Recommend Documents