SPE 87006 Fast Track Development Strategy For New Discovery Adjacent To Giant Producing Gas Field A Case

e Study Of Vasai East Offshore Field

Rajiv Nischal, SPE, Dr. Ramashish Rai, SPE and A. K. Sood, Institute of Oil and Gas Production Technology, Oil & Natural Gas Corporation Limited, India

Copyright 2004, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE Asia Pacific Conference on Integrated Modelling for Asset Management held in Kuala Lumpur, Malaysia, 29-30 March 2004. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836 U.S.A., fax 01-972-952-9435.

implementation of this development plan is on fast track execution. Introduction Development of marginal fields is being focused by every operator. This is important because a large number of discoveries in recent years are small accumulations and give marginal economic returns. Many authors have presented their approach for development of such fields. Giannnesini [1] et al presented innovative technology to reduce cost. Behrenbruch [2] focused on development planning where as flexible and novel approach have also been addressed by Richardson et al [3], Linda et al [4], and Shaheen et al [5]. Lorenzo et al [6] presented case history to control cost, Bakes et al [7] gives benefits of horizontal wells in Yamm field, Stephen et al [8] presented case history of Telforal field, Odd et al [9] presented a case study of North Sea marginal field. Fras et al [10] presented case study of offshore North West Java. Yu et al [11] presented another case history of offshore marginal field. Similarly Badiyento et al [12] presented strategy for development. Many authors [13-14] have also worked on common aquifer impact. After discovery of Vasai East, a through review of existing works of different investigators were carried out to frame strategies, plans and activities for fast track approach. Vasai Field This field is a giant sour gas producing field, with initial gas reserves of about 284 BCM and thin oil reserve of about 143 MM3. Figure 1 shows the location of the field. Vasai field is a structurally high area situated on the continental shelf between Mumbai high field to the west and city of Mumbai to the East. It is located about 80 km West North - West of Mumbai city. The water depth over the field area ranges from 50 to 65 mts and is spread over an area of about 250 square km. The field was discovered in 1976 and put on production from September 1988. Main hydrocarbon accumulation is within Mukta & Vasai Limestone, which is of Middle Eocene to Lower Oligocene age, with small accumulations in Panna (Basal clastic) reservoir. Based on petrophysical characteristics Vasai Limestone has been divided into three zones namely: Mukta (A zone) Tight Zone and Vasai Formation (B-zone).

Abstract Asset based functioning in companies has been setting examples of fast track development strategy by combining multi discipline functions. This is especially relevant for development of a marginal field located adjacent to a large gas field, hydro dynamically connected at aquifer level. In the case history of Vasai East field, these aspects are presented here. 3-D seismic carried out in the year 2000 around the existing field provided a lead for possibility of a new structure towards east. The first exploratory well drilled in March 2001 led to discovery of new marginal field Vasai East having oil overlain by large sour gas cap and underlain by large aquifer. The field was delineated by mid 2002 after drilling of four additional exploratory wells. It was also concluded that Vasai East field is separated from main Vasai gas field at hydrocarbon level, but is hydro-dynamically connected through a common aquifer resulting in sub-hydrostatic pressures. Immediately after delineation, fast track development strategy was formulated and a core team was constituted by combining functions of geology, geophysics, reservoir, drilling & well engineering, asset, design and engineering and R&D institutes to workout development plans for the field. This paper discusses the combined results of a multidisciplinary team for fast track development, technological options, economization of new infrastructures, techno-economic evaluation of different development options. The cost effective development plan with investment of about US$ 200 million was approved by management in shortest possible time for this marginal field. Since adjoining gas field was being produced at its peak rate, any delay in implementation of this fast track strategy could lead to serious impact of oil recovery of this field. The

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The field achieved peak production of 32.8 MMSCMD. In addition two new well platforms have been planned in the southern side of the field to drain out the less contributing area and maintain a rate of 25 MMSCMD in the coming years. It has been noticed that the reservoir pressure has continuously been declining from initial pressure of 179 kg/cm2 to present level of 129 kg/cm2 with very little support from aquifer.
Mumbai High Panna Vasai East Mumbai City

Vasai

Figure 1 Location of Vasai and Vasai East Fields

Mukta formation is petrophysically poor and developed in limited area. Tight zone, primarily shale, separates Mukta and Vasai Formation but possibility of communication is not ruled out. The Panna (Basal clastic) formation is also tested as hydrocarbon bearing below Vasai formation (deeper by about 1000 mts) in some wells of Vasai field. Vasai formation has about 13-18 mts of thin oil column sandwiched between gas column of 50-100 mts of thickness and water column of 200-300 mts thickness. Out of 13 mts oil column, 7-10 mts appears to be clean oil. Core studies indicated good vertical communication. Initial development scheme was finalized in 1980. The field was developed for production of gas from gas zone. The development was carried out in two phases. Phase I covered 2 well Platforms A, D and a process complex BA. Phase II covered 2 well Platforms B, C and a process complex BB. The plateau design rate was 20 MMSCMD and fluid was transported to land based terminal via a 36, 240 km pipeline. The production was later on increased to 30 MMSCMD with the addition of another well platform E and laying of new 42 pipeline to shore terminal. The existing infrastructure of Vasai field is shown in figure 2 below.
Oil
Gas
FROM BBY. HIGH to SHORE 12 Oil D A 20 BA BP-A 18 BQ1 B 24 BB BP-B 22 BQ2 SG
28 X 70 KM

Vasai East field Discovery & Delineation The analysis of 3-D data acquired for main Vasai Field resulted into identification of structural prospects in the eastern area, which hitherto was unexplored up to the year 2000. The exploratory drilling in this new structure commenced with the well E#2 during March-April 2001. The results of E#2 well provided lead for further exploration in Vasai East area. Two exploratory wells, E#3A and E#4A were drilled to the north and east of well E#2. Both wells proved to be oil & gas bearing in Vasai formation and also struck oil in Panna Formation (i.e. Basal clastic formation located deeper by about 1000 mts). Recently two more wells E#5 and E#6 have been drilled in this area. The eastern well E#5 was dry. E#6 has given gas from the lower part of Panna Formation. The initial testing results of different wells are shown in table 1. The water depth over Vasai East field ranges from 50 to 55 mts. The major oil pool is located within Vasai formation around the wells E#2, E#3A and E#4A. The oil is overlain by a thick gas cap gas in the upper section of Vasai limestone. The N-S to NNW-SSE trending fault on the eastern edge of the closure is taken as the eastern limit of pool, while southern limit is marked by an NE-SW trending cross fault. To the west and north, clear water contact is marked. Table 1 Testing results of in exploratory wells (Vasai formation)
Well Chok e (") FTHP (Bar) 13.36 45.7 97.02 89.64 23.20 Qo / Qc 3 (m /d) 21.0 31.1 3.0 NM 13.5 Qg 3 (m /d) 11500 31808 175696 179390 14319 SBHP (Bar) 147.86 149.26 146.21 152.78 136.82

E-2 E-2 E-2 E-4A E-3A

20 Gas
3

TO
M 230K 6 X

SH

E OR

The Vasai East field has total initial oil & oil equivalent gas reserves of about 75 MMT with initial oil in place of about 79.5 MMm3. Common Aquifer The fluid contacts in Vasai East are different from those observed in main Vasai field. It is concluded that these are two separate hydrocarbon accumulations as shown in figure 3. The fields are separated by a low, sufficiently deep to separate hydrocarbon accumulations. However the fields are in hydrodynamic continuity through aquifer. This has been inferred from sub-hydrostatic reservoir pressure of around 30 bar recorded during production testing in Vasai East wells. The comparative study of pressure data of main Vasai with

30 30

42 X

Figure 2: Process platform, Well platform and Pipeline network of Vasai Field

244 K M

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that of Vasai East field supports the geological model of hydrodynamic connectivity through the aquifer

E#1

E#2

E#4A

Gas Oil Water

Vasai Formation

Development Strategy Vasai field has been at the peak plateau gas production rate. More than 40% of initial gas reserve has been produced. There is continuous pressure depletion. Accordingly a fast track development strategy was adopted. To achieve corporate objective of maximizing project value, the following segmental control strategies were set for different functions: Minimize number of wells and platforms Maximize reservoir recovery and well productivity Optimize production & facilities by sharing nearby facility Minimize both Capex & Opex Implement on short contract schedule Minimize risk by proper well placement Build on past experience of technological options Acknowledge both internal & external risk factors. These strategies are common for most of large size projects. Many authors have advocated several such strategies for fast track development. However their applications to bring significant value addition / cost reduction vary from project to project. The development strategy of Vasai East field was then adopted for development of oil section in the present scheme. Horizontal Wells Many previous works relating to horizontal wells versus conventional wells were reviewed. The successful experience of large scale horizontal well completion and its performance in one of mature giant Bombay High and Panna field were also considered. This key study which has significant impact on Capex, showed that horizontal wells have clear economic advantage over conventional wells in terms of Reducing number of wells Reducing platform slots and size Reducing operating cost Reducing water and gas coning Since Vasai East field is having large gas cap and very large bottom aquifer, application of horizontal well with proper placement of horizontal section showed significant advantage in reducing gas and water coning, which was likely to impact both flow from well, depletion of gas cap energy, and operating cost. Accordingly horizontal bare foot completion for all the wells including water injection wells of Vasai East were adopted as a part of development strategy. The sensitivity runs suggested use of 800 - 1000 mts. long horizontal sections as gas coning was evident with conventional 400 mts long drain hole sections. Sensitivity runs also indicated that well production is very sensitive to horizontal section placement. In order to accomplish correct placement of horizontal section it has been decided to drill a pilot hole through the reservoir section to confirm OWC and GOC. The experience of production from the nearby Panna field (being produced under Joint Venture) where more than 40 horizontal wells have been drilled, many of them with drain hole lengths longer than 400 mts in a 25 mts thick oil column, sandwiched between a gas cap and a thick water column also corroborated these results.

Figure 3 East West cross section through Vasai & Vasai East fields

A good similarity could be seen with Westerose D-3 pool located near Leduce D-3 reef Pool [13] having common aquifer model. Reservoir Simulation Geological model reflect that two fields (Vasai main & Vasai east) are hydro dynamically connected through a common aquifer. Several previous studies have been carried out on fields having common aquifer in different hydrocarbon accumulations. It has been concluded that pressure interference need to be accounted for in all such common aquifer reservoirs. Accordingly, the reservoir simulator of Vasai East field was set up by sub-surface team of Asset, incorporating the effect of continued gas production from the adjoining Vasai field on a small 3 layer, 30 x 32 grid model for fast track results. Setting up a simulation model of entire Vasai field, though desirable was not possible in fast track approach. Full model will be taken up in due course of development. The model initialization parameters are given below in table 2. Table 2 Reservoir initialization parameters
GIIP (BCM) IOIP (MMm3) Oil column (mts) Gas cap column (mts) Initial pressure (bar) at 1733 mts Vasai (Model) 109 45 10 100 178.6

simulation
Part Vasai East (Model) 8.5 81.6 30 as per map 178.6

model

A sensitivity study was carried out by varying the degree of support from water-aquifer. With partial aquifer support from the bottom water, the pressure match in the Vasai main and sub-hydrostatic pressure in Vasai East was achieved. This was then used to simulate development plan.

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Development Variants Studied With all the wells having horizontal bore, a total of six variants were simulated and evaluated for a field life of 10 years to arrive at the recommended development option. Variant-I Depletion with 12 Producers,11 Horizontal & 1 Vertical Variant-II 12 producers of Variant I and water injection @4800 m3/d through 6 Injectors Variant-III (Depletion) Early Production through 2 Sub-sea wells followed by additional 10 wells from platform Variant-IV Water Injection @ 4800 m3/day with Early Production through 2 Sub-sea wells followed by additional 11 wells from platform Variant-V Increased Water Injection @ 8500 M3/D and with same number of wells of Variant II Variant-V-A Water Injection @8500 M3/D with 13 producers and 6 injectors, all wells on stream in April 2004 Variant-V-B Same as Variant V-A with 13 wells, with one in Panna Formation first and all wells on stream from April 2006. One well in Panna formation was added to test potential of this formation. A summary of the parameters of variants considered for development is presented in the table 6. On analysis of results of different variants, the following is noted: Continuous withdrawal from giant Vasai field has impact on oil recovery from Vasai East field Depletion variant-I gives lower recovery of about 5.30 MMm3 up to 2016 Water injection variant-II improves oil recovery to 5.58 MMm3 up to 2016 Improvement in oil recovery is possible by putting the field on early production through sub-sea wells. Depletion variant-III and water injection variant-IV gives a recovery of about 5.45 MMm3 and 6.37 MMm3 respectively up to 2016. Enhanced water injection has significant improvement in oil recovery and gives oil recovery of 7.5 MMm3 up to 2016 in variant- VB Recommended Development Variant The major consideration in selection of Variant for development was the predicted behavior of reservoir pressure, cumulative production and the terminal rate of oil production at the end of field life. Variant VA & VB were improvised versions of Variant-II. Variant-III and Variant-IV were not considered as drilling of sub-sea wells, tie up and creation of temporary production facilities was not practical, expensive as time gap arrangement & low success of work over jobs. Variant VA though highly attractive w.r.t. oil gain but this Variant was not practically feasible to implement by April 2004. Variant VB, (with enhanced water injection rate of 8500 m3/d) has been recommended instead of Variant-I because of the following reasons: Terminal reservoir pressure is higher.

The terminal oil production rate is higher There is further scope of economic exploitation beyond terminal year Utilizing one additional well for production from Panna formation (Basal clastic) is an added advantage The economic life of field is possible to extend further The cumulative oil and gas production is higher.

The predicted pressure production profile of recommended Variant is given in table 3 including production from Panna formation. Table 3 Vasai East Production Profile for 10 years
Year 2006-07 2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14 2014-15 2015-16 Oil 3 (M /D) 2481 2426 2293 2076 1800 1629 1512 1186 995. 873 Gas (mmscmd) 0.303 0.280 0.481 0.699 0.961 1.077 1.049 0.799 0.639 0.545 W/C (%) 0.6 2.5 6.9 13.5 23.0 33.4 44.4 52.6 58.5 63.0 Pressure (bar) 136.2 133.9 131.0 127.6 123.8 119.8 116.0 112.8 110.1 107.9

Facility Development Options In order to create various facilities for drilling, gathering, process and export of the envisaged production, various alternative development options were examined. The basis considered is as follows Peak oil rate (M3/D): 2323 Peak Gas Rate (MMSCMD): 1.5 Peak Injection gas rate (MMSCMD): 0.294 Peak liquid rate (M3/D): 2720 Peak water Injection rate (M3/D ): 8585 Field life: 25 years Oil rate (US $ per Barrel): 18 Gas Rate (US $ per Million BTU): 1.1 Oil Degree API: 39 Gas Gravity: 0.74 H2S (PPM): 250 400 Several conceptual development options were framed, evaluated and screened. The options considered are: Option 1: 2 well platforms and one bridge connected process platform EP at one well platform EA in Vasai East field. Option II : 2 well platforms and one process platform EP bridge connected to existing Vasai BA complex Option III : 2 well platform and processing at nearby Panna field process platform Option IV : 2 well platform & processing at FPSO in Vasai East field

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Option V : Sub sea flow with FPSO in Vasai East field The water depth around this field is about 50 mts. Well intervention in sub sea wells is much costly as compared to platform completed wells. Sharing of existing facility will be minimal. Accordingly sub sea well completion is not recommended. Option VI : 2 well platform & processing through Jack up production system bridge connected to EA well platform in Vasai East field Option VII : 2 well platform & processing through refurbished Jack up production system bridge connected to BA Complex of Vasai field Jack up production system in place of a process platform was evaluated. For field life of around 25 years for oil & gas production from Vasai & Panna formation, an old refurbished Jack up production system was not recommended as its residual life was not adequate. Option VIII : Re-locatable Platforms option in Vasai East field Re-locatable well platforms (suction piled) are presently under development for marginal fields. These relocatable platforms are being developed to provide advantages over traditional fixed platforms with the flexibility of mobile unit. These units are said to be competitive when compared to both piled jacket solutions and jack-up platforms equipped with traditional jacking systems. They are considered. Where the field life is short Where topside facilities has to be modified in future Turnbull et al [15] have discussed in detail about these mobile platform concept. These units were evaluated for well platforms and process platform of Vasai East. It is observed that no such mobile platforms exist for 10 wells plus three risers. No standard process design is available for facilities with topside weight in excess of 6000 tonnes. Such units have also not been field proven. Accordingly these units were not considered technically viable option for Vasai East. Sharing facility of Vasai main field While considering above different alternative options, main focus was to minimize cost by sharing nearby facility. One of the main process complexes - BA was located about 7.5 km west of Vasai East. This complex comprised of one four legged well platform A, one six legged process platform BA, one six legged high pressure gas compression platform CPA and one four legged living quarter platform LQ, all bridge connected to each other. This complex is also having oil & gas processing for about 795 m3/d, effluent treatment and export pipelines for oil & gas connected to land based processing stations. In order to meet our set strategy of using nearby facility, reducing capital and operating cost, it was considered important to identify the spare capacities of different facilities, equipments & pipelines. A multidisciplinary team surveyed the complexes, analyzed present and future production profiles of the fields and identified the list of spare able capacities.

Accordingly it was decided to locate the new Vasai East process platform for oil & gas processing, water injection and gas compression; bridge connected to existing BA process complexes. This development approach eliminated requirement of new additional booster compressor platform for Vasai field, reduction of weight and size, sharing of Living Quarter platform and all spare capacities of existing platform including gas lift gas compressor, flare system, helideck, emergency power, gas booster compressor, gas dehydration, effluent treatment, stand by train, oil & gas export lines, related safety, logistic and separate manpower for operations. This was one of the important cost economic measures adopted in this marginal field development. Other innovative cost reduction measures In all options, a thorough analysis of flow assurance, need for artificial lift, mode of lift, availability of high pressure gas and its quality, product export system etc, were evaluated and optimized. Similarly several other cost measures were adopted in different options. In order to optimize the weight of topside facilities of well platforms, the fire water pump and engine was eliminated and fire water hydrant was drawn from injection water line. Keeping in view, maximum reach of wells from a platform, one well platform of 12 slots and one well platform of 9 slots was finalized. It also decided that water injection wells will not be used for production. Accordingly, the wellheads casing and tubings of W.I. wells were selected with normal metallurgy, instead of higher alloy metallurgy (13 chrome) required for sour service, for producing with H2S content of about 250-400 ppm of Vasai East. The water injection lines were selected of normal flexible pipe to extent its life in comparison to standard carbon steel pipe with significant cost advantages. Since additional low pressure booster compressor was planned for main Vasai Field on a separate platform, it was merged with the scheme of Vasai development. This resulted in elimination of one platform structure, sharing of this booster compressor for compression of Vasai east associated gas and all related utilities. This resulted into significant cost reduction. Three large booster compressors having combined compression capacity at 2.5 MMSCMD were idle. These compressors were taken as part of additional booster compressor facility, reducing booster compressor requirement significantly. Accordingly the platform size of the integrated platform was reduced significantly. Screening and selection of development option Options IV to VIII were rejected on technical screening. Techno-economic evaluation of options I to III was carried out and summary of results are placed below in table 4. Option II i.e. 2 well platforms and one process platform bridge connected to existing BA complex is found most economically viable option and is recommended for implementation. In addition sensitivity analysis was carried out for selected option II for variations of different cost parameters. It

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can be seen that the project is viable under different scenarios as shown in table 5.

EA to EB water injection line 8 x 37.5 km BA to EA Gas injection line 6 x 7.5 km EA to EB Gas injection line 4 x 3.5 km

Table 4 Development options evaluation summary

Capex MM US$ Opex US$ MM IRR (%) NPV @ 14% MM US$ 13.16 54.11 (-)43.75

Option

Option - I Option - II Option - III

247.92 205.21 287.08

284.58 220.21 473.33

15.61 21.50 8.54

Table 5 Sensitivity Analysis based on CAPEX, OPEX and Production rate variation
Sl.No. 1 2 3 4 5 6 7 8 9 Parameter Base Case Capex + 10% Capex + 20% Opex + 10% Opex + 20 % PDN. ( ) 10% PDN. ( ) 20 % Both Capex & Opex +10%,PDN ( ) 10 % Both Capex & Opex + 20% PDN () 20 % NPV @ 14% in MM US$ 54.11 39.72 25.34 50.31 46.50 32.23 10.34 14.21 (-)26.27 IRR % 21.5 19.08 17.01 21.05 20.60 18.58 15.51 15.88 10.63

Sharing of major spare capabilities of existing BA process complex Compressed & dehydrated Gas lift gas Living quarter Helideck Flare stack Emergency power Gas Booster compressor from 20 bar to 105 bar (supply pressure) Gas dehydration and regeneration Oil dehydration Effluent treatment & disposal Stand by existing oil separation & processing Oil & Gas export system & pipeline All safety, logistic, manpower A schematic of the final selected option recommended for development is show in figure 4 below

BA

EP W/F

W/F
EB

W/I

W/I

G/L G/L
EA

Facilities of Recommended Options The well fluid from EA and EB will be transported to process platform EP. The water for injection will be transported from EP to EA to EB. Similarly dehydrated gas for gas lift will be transported from BA to EA to EB. To optimize cost, gas is compressed to 20 bar at process platform EP and sent to BA booster compressor for final compression and dehydration. The total facilities include: 12 slot well platform - EA (one vacant slot for future) 9 slot well platform - EB (one vacant slot for future) Well fluid from EA & EB to process platform EP Bridge connected to BA complex. Well fluid processing at new process platform EP in stabilized mode Water injection facilities at new process platform EP. Flash gas compression is 1 X 100% EA to EP well fluid line 12 x 7.5 km EB to EP well fluid line 10x 7.5 km EP to EA water injection line 10 x 7.5 km

Figure 4 Schematic of selected option for development

Project Status The project is currently under execution and is expected to come on-stream on 1st April 2006, while well drilling will commence from beginning of 2005 after installation of Jacket. Conclusions Many marginal oil accumulations have been discovered in Western offshore, India. The development and monetization of these discovered assets require innovative strategy, technology, planning, approach and cost reduction measure to make them viable. Development of Vasai East, a marginal oil field on fast track has been made possible through well defined strategies & plans, innovative new technology application. Cost control & optimization and a multidisciplinary task based parallel working with a real time integration of functional tasks of geological modeling, reservoir simulation innovative horizontal well drilling, well design & well completion,

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pressure maintenance, integration of existing and nearby facilities and pipelines simulation of fluid flow dynamics and pipelines optimization, material, equipments and facilities, optimization of platform structures etc. All these initiatives resulted a significant reduction of capital and operating cost and making this marginal field economically viable with present product prices of the country. Acknowledgments We thank the management of ONGC for the permission to publish this paper. Sincere thanks are also to Mr D R Ghosh, Basin Manager, WOB and his team, Mr V P Gupta, Asset Manager (B&S), Dr R V Marathe, Sub Surface Manager (B & S), the Subsurface and Surface team of the Asset, Mr B K Tiwari of Institute of Reservoir Studies, Mr A V Rao of Engineering Services, Mr Soni of Drilling Services, Mr N A Siddiqui of Well Services and Mr C P Singhal, IOGPT who have contributed in their respective areas in arriving at the development scheme for Vasai East and for its use in this paper. The view presented in this paper are of authors and do not necessarily represent the management view. Nomenclatures Capex = Capital Cost FTHP = Flowing Bottom Hole Pressure MMUS $ = Million US $ MMT = Million Metric Tonnes Opex = Operating Cost PDN = Production Profile Qo = Oil Rate Qc = Condensate Rate Qg = Gas Rate SBHP = Static Bottom Hole Pressure

7.

8.

9.

10.

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12.

13.

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15.

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Bakes A. Phillip, Robb W. Douglas, Rasmussen J. Christian, Tracy F. Kevin, Horizontal Wells in Yemen Make a Marginal Field Economic, SPE 37058, SPE Horizontal Well Technology, 18-20 November, 1996 Jewell Stephen, The Telford Field Development, SPE 39047, SPE Carribbean Petroleum Engineering Conference, 30 August - 3 September, 1997 Apeland J. Odd, Statoil A.S., Flaate Svein, Skoglunn Tom, Yme, A Marginal Field Development in the North Sea, SPE 49126, SPE Annual Technical Conference, 27-30 September, 1998 Silitonga J.P. Frans, Purantoro Ronnie Simandjuntak H. Gustaf, ESS/EST Marginal Field Development in ESouth Area, Offshore Northwest Java, SPE 54276, SPE Asia Pacific Oil & Gas Conference, 20-22 April 1999 Hongil Yu, Shunqiong Song, A Successful Example of An Offshore Marginal Oil Field Development - A Case History of Wei - 11-4 Oil Field in Beibu Gulf Basin, SPE 54354, SPE Asia Pacific Oil and Gas Conference, 20-22 April, 1999 Thomas Budiyento, Galuccio M Miguel, Dharma Wira, Mitrodihardjo Sudharmono, Pasaribu Jonny, Marginal Field Development Strategy, Kartini Field, Offshore Southeast Sumatra, SPE 54280, SPE Asia Pacific Oil and Gas Conference, 20-22 April, 1999 Hnatiuk John, Martinelli J W, The Relationship of the Westerose D-3 Pool to other Pools on the Common Aquifer, 18th Annual Technical Meeting, The Society of CIM, Banff, Alta, May 1967 Moore W D, The Pressure Performance of five Fields completed in a Common Aquifer, Petroleum Transactions, AIME, Vol 195, 1952 Turnbull Glenn, Relocatable oil and Gas wellhead & production platforms for small and marginal field development, U461,Petrotech, 9-12 January New Delhi 2003 Western Offshore Basin, Feasibility Report on Vasai East Field Development, Internal ONGC report Nischal Rajiv, Conceptual Study of development of Vasai East as oil and gas producing field, Internal ONGC report

References
1. Giannnesini J.F., Champlon D. Badour Innovative Technologies Reduce Cost of Offshore Marginal Field Developments in Northwestern Europe, SPE 22028, SPE Hydrocarbon Economics and Evaluation Symposium, Dallas, USA, April 11-12, 1991 Peter Behrenbruch, Offshore Oilfield Development Planning, SPE 22957, JPT, Aug 1993, P-735 - 743 Richardson S.M., Blackburn N.A. Shere A.J. Exploration B.P, The Don Field : A Flexible Approach to the Development of a Marginal Field, SPE 23078, SPE Offshore Europe Conference, Aberdeen, 3-6 September 1991 Cross Linda, Abbott Syd, Hatchwell E.P.C., Zack J.G. McGrory K.F., U.K. Chevron, A Novel Approach to Future Marginal Field Development Using Existing Infrastructure, SPE 28189, SPE Oil & Gas Economics , 89 June, 1994 Shaheen M Emam, Schultz Steve, Innovative Solutions in Developing Marginal Gas Fields East Shukeir Marine (ESMA) Gas Field, SPE 53134, SPE Middle East Oil Show , 20-23 February 1999 Pretto Lorenzo, Ghareeb Mohamed, Cost Control & Development and Production of Egyptian Western Desert Marginal Fields SPE 36849, SPE European Petroleum Conference, 22-24 October, 1996

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Table 6 Parameters of variants considered for development

Sl. No. PARAMETER I 1. 2. Artificial Lift Mode Gas Lift Facilities No. of Producers Sub-sea wells No. of Injectors No. of Process Platform Well Platforms Oil & Gas Evacuation Production Performance Oil Production (MMT) Gas Production (BCM) Start of Production Producing life (years) 3 Plateau Production Rate (SM /D) Terminal Production Rate 3 (SM /D) Initial Reservoir Pressure (Bar) Terminal Reservoir Pressure (Bar) Initial Water Injection Rate 3 (SM /D) Start of water Injection Peak Water cut (%) Gas Lift 12 Nil Nil 1 2 Existing Line 4.68 2.11 Apr-06 15 2123 158 134.10 87 NA NA 13.10 II Gas Lift 12 Nil 6 1 2 Existing Line 4.60 1.80 Apr-06 10 2202 703 135.00 104 4800 Apr.06 59.90 III Gas Lift 12 2 Nil 1 1 Existing Line 4.50 1.80 Apr-04 10 2086 311 143.00 97 NA NA 13.50 VARIANT IV Gas Lift 13 2 6 1 2 Existing Line 5.23 2.62 Apr-04 10 2208 845 143.00 108 8500 Apr.04 64.00 VA Gas Lift 13 Nil 6 1 2 Existing Line 5.80 2.35 Apr-04 10 2234 810 143.00 112 8500 Apr.04 67.00 V VB Gas Lift 13 Nil 6 1 2 Existing Line 6.19 3.18 Apr-06 15 2482 525 136.20 101 8500 Apr.06 76.00

3.

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