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(1.5.600) Brownfield development and recovery enhancement strategy in offshore mature carbonate reservoirs - a technological perspective Brajesh Kumar Tiwari and Krishna Nand Jha* Sub-Surface Team, Assam Asset, Oil and Natural Gas Corporation Limited, Nazira, Assam, India * Institute of Reservoir Studies, Chandkheda Campus, Ahmedabad- 380005, Gujarat, India E-mail: [email protected] and [email protected] Abstract Brownfield development has gained momentum in recent past as the world oil survey indicated that around 30-40% of world total production is from old/mature oil fields. The advances in interpretation, drilling and completion technologies have changed the field production scenario of new and mature oil fields. In majority of cases around 25-30% of the oil inplace has been produced from these fields. The journey beyond this is quite challenging and can be performed only with the knowledge base and available technology today. This case is a text book example of such an effort in management of brownfield development. The fields Heera and South Heera under water flooding since 1990 are on production since November 1984 and January 1995 respectively. Field was passing through the phase of continuous decline in oil production and increased water cut. In last few years there were no major input in terms of infill locations and work over jobs which may be reasons for deteriorating well bore condition leading to decline in oil production. Currently the field encounters the major problems of increase in water cut due to preferential movement of water through high permeability streaks, sub-optimal production from existing wells, large well spacing and pressure sinks in some of the areas. The field, at its current stage of exploitation, offers significant flexibility for revitalization plan under redevelopment. There is possibility of production optimization as well as optimum exploitation. Under brownfield development, wells which are producing sub-optimally are taken up for enhancing the production by sidetracking them towards better saturation areas and completing them as multilaterals/ drainholes with two to three branches for enhancing the production/productivity. Similarly, water injection is also planned to be enhanced by drilling additional injectors, relocating some of the existing conventional and converting them into drain holes. Massive hydro-fracturing is also planned in some of the poor injectors that are not getting addressed through sidetrack-drain hole. Since in South Heera field all the pays have better reservoir characteristics, wells which are on commingled production are planned to be completed as dual producers in two or more pays with gas lift facilities after making them drain holes. The potential areas are prioritized for production enhancement by analyzing availability of number of pays, current oil saturation, reservoir properties and productivity indices. Commensurate water injection is kept in mind to have better reservoir management of all the formations. Existing empty slots are to be used for drilling early in the life of the project, to obtain the economic advantages of early revenue. Also, these resources are to be used as low risk opportunities to test technologies and geologically high risk areas. New drilling and completion technology will be inducted early in the project life to derive maximum economic benefit. Under Greenfield development, the areas north and west of HC platform, north-east of HD platform, west of HSA platform and area around HT and HSB platforms offer significant scope of additional infill wells. New platforms are planned to be installed to drill these wells with a view to target the unexploited areas, reduce the acreage per well and thereby enhance the production.

This paper deals with the geological and geophysical challenges and reservoir management of offshore field development with initiatives as well as measures taken for production and injection for recovery optimization.

Introduction Heera field is situated 70 km South-West of

HeeraHeera

Mumbai City in the Arabian Sea and 140 km South East of Mumbai High at an average water depth of about 50 m (Fig-1). The field was discovered in 1977 and 1990. Subsequently, the field was delineated with eighteen exploratory wells and proved to be one of the major hydrocarbon bearing structures in Mumbai Offshore Basin with a number of reservoirs of commercial oil and gas accumulations. These are Basement, Basal Clastics of Paleocene, Bassein and Mukta Formation of Eocene and Lower Oligocene and Heera formation of Lower Oligocene. Based on geological and reservoir data from the exploratory wells. A phase wise development plan was coceptualised. Heera field was developed in three phases. Phase-I & Phase-II development was carried out mainly for developing the Bassein Pay, the main pay which has 2/3rd of Oil In-place (OIIP). This pay was developed by drilling 110 wells through 10 platforms. Phase-III development was carried out for developing the Mukta pay, which is better developed in the crestal part of Heera field by drilling of 24 development wells through two platforms. Fig-2 indicates structure contour map at the top of Mukta pays for Heera and South Heera field. South Heera field, which is lying in the southern part of the main Heera field, was developed by installing two platforms and drilling of 24 development wells from through these two platforms, 3 wells from HT platform and converting one exploratory well into water injector.

Fig-1: Heera Field Location maps

Performance History and Present Status

Commercial production from the Heera field started in November 1984. The oil production was mainly from Bassein, Mukta & Panna formations. Bassein pay is well developed except in the crestal part of the field and is about 100 m thick in the west. Out of 91 wells on production, 56 wells were completed in Bassein pay and around 70 % of the total oil production of Heera field was from this pay. Mukta pay of 10-12 m thickness, developed in entire Heera field. This formation is relatively tight as compared to Bassein formation but better developed in crestal part of the field. Under Phase-III development, two platforms were commissioned and 24 development wells were drilled for exploitation of Mukta pay in crestal part of the field. Fig-3 depicts the time schedule of installation of platforms of various phases. Presently 17 wells are completed in Mukta pay and are producing about 8 % of current oil production. Panna formation is also developed in entire field but is better developed in south-eastern part of Heera field. Presently 6 wells are producing about 10 % of the current oil production

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from Panna pay. This formation has good potential for further development. Under Additional Development Part-II, two wells are planned to be completed in Panna formation in this area.

Heera formation consisting of 40-50 m thick alternations of limestone and shale is developed in the entire field. Some of the limestone layers in this formation are porous and hydrocarbon bearing. Because of patchy development of pay, there is no separate development plan for this pay. At present only one well is completed in this formation. However, in future, the poor producers in Bassein/Mukta formations will be completed in Heera formation, wherever it is better developed. The field produced under depletion drive till September 1990. By this time the reservoir pressure dropped to 1300-1375 psi from initial reservoir

pressure of 2150 psi and the field experienced sharp decline in production. During depletion mode of production there was no water cut indicating negligible aquifer support. Water injection was initiated in September 1990. With peaking of water injection to the planned level, the production stabilized during 1992-93 with increase in water cut. Production started picking up further with the installation of gas lift during 1993-94 and reached to the level of 51000 bopd with water cut of 25% in August 1996. Currently the field is producing oil @32390 bopd with 49% water cut through 91 wells. The current water injection rate through 35 injectors is 87745 bwpd. The current area weighted average reservoir pressure is 1985 psi. The incremental voidage compensation is of the order of 110 % and cumulative voidage compensation is about 65 %. The cumulative oil production as on 01.04.05 is 33.239 MMt which is about 16.0% of OIIP in Proved category. In South Heera field, all the above pays viz, Heera, Mukta, Bassein and Panna are better developed. Initially most of the wells were completed as dual but later on during installation of gas lift wells were converted into single commingled producers. It is observed that the performance of the dually completed wells was better than the performance of commingled production. The estimate of formation wise production is not possible due to this commingled nature of completion. Commercial production from South Heera field started from January 1995 after commissioning of two platforms HSA & HSB. Three wells (HT-1, HT-9 & HT-10), which were earlier part of Heera field have been considered as a part of South Heera field after review of fault patterns. These three wells were producing oil @ 3000 bopd since November 1990. The peak production level of 40600 bopd was acheived in July 1995. In this field full-fledged water injection started in October 1997. By this time cumulative oil production was 4.987 MMt. Due to delay in initiation of water injection from HSA & HSB platform

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wells, there was a sharp decline in production which could not be arrested even after installation of gas lift in 1996. Some of the wells started producing water from the early stage of exploitation of the field indicating the source of water may be from the aquifer present across the fault. In South Heera field the initial reservoir pressure was 2150 psi which declined sharply to 1850 psi in 1996 due to high liquid withdrawal and further to 1700 psi in 1999-2000. In due course of time the declining trend of pressure was arrested and currently it is about 1700 psi. Presently the field is producing oil @12315 bopd at 61 % water cut through 21 oil producers and the current average water injection rate through 7 injectors is 49180 bpd. Fig-4 represents the production performance curve of Heera and S Heera field. The incremental voidage compensation is of the order of 115 % and cumulative voidage compensation is about 55 %. As on 01.04.05, cumulative oil production from South Heera field is 10.05 MMt which is about 14 % of OIIP in Proved category.

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As on date, there are 172 development wells including 31 horizontal/ drainholes and 6 multi-lateral wells in 15 platforms of Heera and South Heera fields. Status of development wells as on April 01, 2005 is placed in Table-1. Seven vacant slots are available on 5 platforms of Heera field. The peak oil production rate from Heera & S. Heera field was 88625 bopd with an average water cut of 22 % in 1996. Currently 112 wells are on production at an average oil rate of 44705 bopd with water cut of 53 %. Six wells are non-flowing due to high water cut and poor influx. Water injection is in progress through 42 wells @ 136925 bwpd for voidage compensation and pressure maintenance. 12 injectors are closed for Reservoir management/poor injectivity. As on 01.04.05, the field has produced about 43.289 MMt of oil with an oil recovery of 15.6 % of OIIP in Proved category. Water injection is in progress, mainly through peripheral and pattern injection. Injection and production are mostly through commingled conventional completions. The Injector to Producer ratio is 1: 2.2. At the commencement of water injection, the wells which were producers earlier were directly converted to injectors without profile modifications and without backwash provisions. In the northern part and western flank of Heera field the reservoir is tight. As a result the required quantity of water is not getting injected. Challenges and approach for Brown Field Development

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Fig-6: Well log correlations of Heera and S Heera Fields (N-S)

Classical reservoir engineering techniques as well as geocellular reservoir model were used as integrated evaluation tool to select the most suitable field redevelopment option. The evaluation process began with problem identification or framing, uncertainty analysis and then field simulation based field redevelopment options in consultation with

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facility engineer, drilling engineer and production engineers. Finally refinement of the field redevelopment scenarios were worked out keeping minimum risk, quality improvement and phase wise development in mind. The main reservoir redevelopment strategy includes oil recovery maximization, jacking up of production, targeting sweet zone, exploitation of un exploited reservoirs, workover optimization as immediate results.

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Fig-7: Ø, Sw and Permeability distribution in wells of

Heera and S Heera Field (N-S)

Well wise and sector wise pressure analysis indicate the presence of high pressure area around the injectors and low pressure area around the producers. A considerable amount of pressure gradient exists from the periphery to the up dip part of the reservoir. Higher pressures around the injectors indicate poor dissipation of injected water towards producing area. The reservoir heterogeneity demand for lower well spacing as the current well spacing in the field is non-uniform and large (~ 225 acres/well). Presently out of 112 wells there are about 37 wells which are producing oil at a rate <200 bopd, 45 wells are producing between 200 & 500 bopd and 31 wells are producing at a rate >500 bopd. About 50 wells are producing oil with water cut more than 50 %. Effect of water injection is not uniformly felt in all parts of the field. In some areas with good injection support, the layers with relatively high permeability get the water injection effect early while the tighter ones continue on depletion mode. Pressure sinks are developed in some parts of Heera field. Higher pressures around the injectors indicate poor dissipation of injected water towards producing area. Characteristic Hall’s plot (Fig-5) does indicate the behaviors of injectors so that remedial measures are needed for revival of such injectors.

Fig-8: Upscaled picture of Reservoir model of Heera field

As a part of rejuvenation of the field and understanding the current state of production reevaluation of the existing data and re characterisation of new data have been carried out for

better understanding of the reservoir. The petrohysical parameters for log interpretation i.e. a, m and n parameters were reevaluated and the well logs were reprocessed. The reprocessed log data has been used for building up of the geological model using geostatistical approach. Mukta and Bassein pay being the major hydrocarbon bearing part have been the focus area for recovery optimization in short term. Other hydrocarbon bearing area Panna formation and Alternation and Bandra pay (Gas bearing zone) have also been given weight age for optimum

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exploitation of the hydrocarbon. Fresh log correlations have been generated (Fig-6) and the same data set has been used for spatial distribution of the reservoir properties (Fig-7). The generated properties were compared qualitatively with the pressure transient studies as well as production logging studies for attaining a suitable subsurface picture of the reservoir. The fine scale reservoir model has been upscaled for creation of reservoir simulation model of Heera and S Heera field separately(Fig-8). The simulation model was taken for history match. Water cut, reservoir pressure and gas oil ratio have been given priorities for well wise history match. After attaining a suitable history match the same model is taken for future performance prediction. The total performance prediction has been carried out in stages. In first stage, wells (producers as well as injectors) for workover (addition of zone/Sidetracking) were identified. In second stage the vacant slots available on the platforms were suitably placed as infill wells. In final stage the sweet lefts over zones have been targeted for recovery optimization and optimum exploitation. Result and Discussion Under Brown field development and as a prelude to redevelopment of total Heera field, a pilot project, HR platform in the western flank of Heera field was taken up for work over jobs from 2005. The platform was producing oil @ 2500 bopd with 65 % water cut before WOJ through 8 wells. In this area, the reservoir is tight. Detailed reservoir studies, log analysis and micro correlation were carried out to identify undrained reservoir, layers contributing high water production. Wells were sidetracked and converted to horizontal drain holes and suitably placed in better oil saturation area. Use of state of art technology (e.g. SRDH and MRDH) made it possible to achieve better placement of wells with low horizontal drift and high dog-leg. This further helped to negotiate minimum shale thickness above the pay and avoiding extra casing/liner. Use of non damaging mud during drainhole phase and surge plug helped faster activation of wells. Workover of five oil wells of this platform has improved the oil production rate from 1325 BOPD to 4850 BOPD and a substantial decrease in water form 75% to 10% has been achieved. Based on the same analysis injector viz. HR-7 with zero injectivity was also worked over in the same platform. A 400 m drain hole with a branch was made in the strike direction and after thorough back wash the well was re-completed with back flow facility. Further, with same concept, well HS-9 of HS platform was taken up for work over in Sept.’05 for drain hole drilling. Before work over job the well was producing about 100 bopd with 80% water cut. After detailed studies and micro correlation, a 200 m drain hole was planned in the top part of sweet zone in Bassein formation. The drain hole was drilled using non-damaging clay free mud. The well was activated by surge plug. After work over, the well started producing oil @850 bopd with 10 % water cut. Similar jobs planning for selected wells of Heera and S Heera field have been done and been conceptualized in Brownfield Development. To improve the voidage compensation and better sweep jobs like Relocation of some of the down dip injectors and placement along the strike direction, Relocation of offending up dip injectors, Hydro-fracturing of poor injectors, Drain hole drilling to increase water injection, Profile modification and Regular back flow arrangement in all the injectors. The current field experience, performance analysis of the well/platform and field, current visualization of near geological picture through geostatistical approach and improvement in understanding of fluid dynamics based on field history match all coupled together provided the current fluid distribution as well as possible potential area for recovery optimization as well as enhancing production from the field. The present approach also provided the exploitation strategy for the unexploited hydrocarbon zones in present economic scenario. In addition to the current production as well as recovery optimization is also backed up with future exploitation scenario of the low potential hydrocarbon horizons also. The updation of the existing geological model based on the workover data, infill data and performance history certainly guide the recovery optimization process in right direction.

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Conclusions The current geological geostatistical model is prepared for the major hydrocarbon bearing horizons but a due weightage has also been given to the low as well as lowest potential horizons also for future target. The history match has provided a better understanding of the current hydrocarbon distribution which in turn will help in targeting the left over hydrocarbon and thus recovery optimization process. The present analysis of water injectors do suggest for change in water injection strategy in the field and this has been incorporated in the current redevelopment proposal for attaining the better reservoir health. This approach does help in better voidage compensation as well as pressure maintenance in the field. In totality the current study focuses on (i) brownfield development, (ii) drainage/ exploitation of left over oil and (iii) oil exploitation in inter and intra platform areas with reduction in well spacing (iv) opening up of the new area northwest of HC platform. The redevelopment planning has been formulated to take care of the above areas with (i) work over of poor producers/ injectors, (ii) drilling of wells on vacant slots and (iii) location of sweet spots. The present study is likely to add 10-12 MMt of oil by 2030 with increased water injection of 2, 00,000 BWPD by 2008-09. The current redevelopment plan also targets the small and isolated nearby pools for monetization of the asset also. Acknowledgements The authors thank the Asset Manager, Sub Surface Manager, Area Manager and officers of Neelam Heera Asset of Mumbai Region for their support and value addition during the completion of the study. References 1. Samantha Hanley and Robert Navo: “Brownfields-Tool to Manage the Challenges”,

Schlumberger Information Solutions, July 2004, pp1-8. 2. Usman Ahmed: “Brownfields”, White Paper, Schliumberger, January 2004. 3. D B Silin, R Holtzman, T W Patzek, J Brink: Monitoring waterflood operations: all’s Method

Revisited, SPE 93879 presented at the 2005 SPE Western Regional Meeting held in Irvine, CA, USA, 30 March-1 April 2005.

4. Hazarika. G, Tiwari B. K. et al: “Comprehensive Review of Heera and S Heera Fields”, Field Development Group, IRS, Ahmedabad, July 2002.

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