The subject reservoir is a heterogeneous carbonate formation in a giant field located offshore Abu Dhabi. Five gas injection pilots were initiated in late 2001 in the Eastern, Central and Western parts of the field both as secondary and tertiary recovery methods to evaluate the benefit of gas injection for pressure support and for recovery improvement. With less than 10% of HCPV gas injection, the pilots to date have provided valuable insight on production performance and pressure support, gravity override, swelling effect and flow assurance issues (such as asphaltene deposition) in the field. Using a 3D compositional model, a sector modeling study was carried out for comprehensive evaluation of the pilot performance to date and to predict definitive results within reasonable time frame (3-5 years) which will have ramifications on long-term full field development decisions. Additionally, the objectives of simulation efforts were to evaluate different recovery processes (gas/water/WAG) and assess key reservoir uncertainty (volumetric sweep) due to reservoir heterogeneity (high permeability streaks). Initially, the sector model was history matched with nine years of pilot performance while both reservoir heterogeneity and well spacing sensitivities were tested in the model. The history matched sector model was utilized to predict performance under different operating conditions using both gas, water and water alternating gas (WAG) injection methods. This paper describes the pilot performance, field observations and results of a sector model study including history match, sensitivity and predictions under different injection scenarios on two of the pilots. Based on the performance and surveillance data gathered on the two pilots and sector modeling study, it was established that both pilots have met their objectives and can be concluded. Through the integration of field observations and sector modeling work, the study provided valuable insight on optimum recovery processes, well spacing and well completion requirements for long-term field development.
The Bahrain Oil Field was the first oil discovery in the Gulf Region in 1932 and is now in a mature stage of development. Crestal gas injection in the oil bearing, under saturated, layered and heavily faulted carbonate Mauddud reservoir has continued to be the dominant drive mechanism since 1938. Thirty eight 40 acre 5-spot waterflood patterns were implemented from 2011 to 2012. These patterns were located in both the South East and North West part of the Mauddud reservoir with a maximum injection rate of 80,000 bbl/day. With less than 10% PV water injected as of December 2012, premature water breakthrough was observed in most of the producers. Rapid water breakthrough in Mauddud A (Ba) is attributed to presence of high permeability vugs and layers resulting in water cycling and poor sweep in the matrix leaving bypassed oil. Following recommendations from the 2013 partner Peer Assist, the South East and North West waterfloods have been converted from pattern to peripheral with downdip wells providing water injection. Peripheral re-alignment has arrested the production decline, reduced water cut and stabilized production. Surveillance data such as bottomhole pressure data, production logs, reservoir saturation logs, temperature logs and tracer data form the basis of understanding waterflood performance. Additionally, an array of analytical tools were used for diagnosis and analysis. Amongst the diagnostic tools, the Y- function helped to understand water cycling and sweep; the modified-Hall plot assisted in understanding the high-permeability channel or lack thereof and the water-oil-ratio (WOR) provided the clue on fluid displacement. Additional plots such as the "X" plot, decline curve, Cobb plot, pore volume injected vs. recovery, Jordan plot, and Stagg's plot were generated to gain insight on the waterflood. Based on the waterflood analysis, a field study was initiated in December 2016 by shutting more than 80% of water injection followed by complete shut-in in September 2017. The purpose was to reduce the water cut, improve production taking advantage of gravity drainage effect of gas injectors located up dip of waterflood areas. The implementation of water injection shut-in is still ongoing in the Bahrain Field and pressure/production performance is being closely monitored. Improved production performance is observed following water injection shut-in. This study underscores the importance of modern analytical tools to diagnose and analyze waterflood performance. This understanding also paves the way for much improved learning to take appropriate actions and help devise long-term reservoir management strategy.
Bahrain oil Field being the first oil discovery in the gulf region in 1932 is now in a mature stage of development. Crestal gas injection in the oil bearing, under saturated, layered and heavily faulted carbonate Mauddud reservoir has continued to be the dominant drive mechanism since 1938. Thirty-eight 40-acre 5-spot waterflood patterns were implemented from 2011 to 2012. These patterns were located in both South East and North West part of Mauddud reservoir with a maximum injection rate of 80 MBWPD. With less than 10% PV water injected as of December 2012, premature water breakthrough was observed in most of the producers. Rapid water breakthrough in Mauddud A (Ba) is attributed to presence of high permeability vugs and layers resulting water cycling and poor sweep in the matrix leaving bypassed oil. Following recommendations from the 2013 partner Peer Assist, the South East and North West waterfloods have been converted from pattern to peripheral with down dip wells providing water injection. Peripheral re-alignment has arrested the production decline, reduced water cut and stabilized the production. Surveillance data such production logs, reservoir saturation logs, noise logs, temperature and tracer data form the basis of understanding waterflood performance. Additionally, an array of analytical tools were used for diagnosis and analysis. Amongst the diagnostic tools, the Y- function helped to understand water cycling and sweep; the modified-Hall plot helped understand high-permeability channel or lack thereof and water-oil-ratio (WOR) gave the clue on fluid displacement. Additional plots such as "X" plot, hydrocarbon pore volume injected vs. recovery, Jordan plot, Cobb sweep plot, Stagg's plot and decline curve analysis were generated to gain insight on the sweep, recovery and remaining moveable oil of the waterflood. Based on the waterflood analysis, a field study was initiated in December 2016 by shutting more than 80% of water injection followed by complete shut-in in September 2017. The motivation was to reduce the water cut, improve production taking advantage of gravity drainage effect of gas injectors located up dip of waterflood areas. The implementation of water injection shut-in is still ongoing in the field and pressure/production performance is being closely monitored. This study underscores the importance of fit-for-purpose surveillance data along with ensemble of modern analytical tools to diagnose and analyze waterflood performance. This understanding also paves the way for much improved learning to take appropriate actions and help devise long-term reservoir management strategy.
This paper presents case histories of horizontal wells transient pressure test interpretations conducted in a carbonate reservoir. The development of non-conventional techniques for interpreting some short-time horizontal well test pressure responses are presented.Horizontal well trajectories as well as fluid flow dynamics can introduce complexities into the horizontal well test pressure response data. In many of such cases, horizontal well tests are not amenable to analysis using conventional methods of well test interpretations. However, for those wells where the early radial and the early linear flow regimes are observed, a test interpretation method developed as 'The Gradient Intercept Method' could be used to implement complete test interpretation satisfactorily. The method precludes the need for the development of late radial flow regime, and consequently, the long shut-in time generally associated with horizontal well testing and the attendant loss of oil production can be averted. A numerical model with PEBI grids is also constructed using a well test simulator to confirm the results obtained from oradient . bIntercept method. 745For cases where the primary objective of a well test program is the assessment of wellbore skin effect, the Short Time Skin Test (STST) is introduced. The STST is essentially a wellbore monitoring technique used in a time-lapse fashion to evaluate wellbore damage. Both the Gradient Intercept and the STST methods are illustrated with field examples to demonstrate their applicability.
The objective of this paper is to present the comparative results of comprehensive analysis of horizontal well productivity and completion performance with vertical wells drilled and completed within same time window in the Mauddud reservoir in the Bahrain Oil Field. The study also focuses on performance evaluation of horizontal wells drilled in different areas of the field. Key reservoir risks and uncertainties associated with horizontal wells are identified, and contingency and mitigation plans are devised to address them. Besides controlling gas production, the benefits of using cemented horizontal wells over vertical wells are highlighted based on performance of recently completed workovers and economic evaluation. Reservoir and well performance are analyzed using a variety of analytical techniques such as well productivity index (PI), productivity improvement factor (PIF), normalized productivity improvement factor (PIFn), well productivity coefficient (Cwp), in conjunction with a statistical distribution function to reflect the average and most likely values. In addition, average oil/gas/water production, cumulative production, reserves, and estimated ultimate recovery (EUR) are compared for both vertical and horizontal wells using decline curve analysis. Furthermore, economics are evaluated for tight spacing drilling with vertical wells, as well as horizontal cemented wells, to optimize future development of Mauddud reservoir. Based on the evaluation, it is inferred that the average horizontal well outperforms a vertical well in terms of production rate, PI, PIF, reserves, and EUR in the field except in waterflood areas. Based on average cumulative oil, reserves and EUR, and well productivity coefficient, overall performance of horizontal wells are better in the GI area in comparison their counterparts in the North/South areas of the Mauddud reservoir, where the dominant mechanism is strong water drive. High gas and water production in horizontal wells are attributed to open-hole completions of the wells and the possibility of poor cementing. A trial has been completed recently in a few horizontal wells using cased-hole cemented completion with selected perforations, resulting in improved oil rates and the drastic reduction of gas to oil ratio. Furthermore, two new cased-hole cemented horizontal wells are planned in 2021 as a trial. A detailed cost-benefit analysis using a net present value concept is performed, leading to a rethink of future development strategies with a mix of both vertical as well as horizontal wells in the GI area. Using the dimensionless correlations and distribution functions, the productivity and PIF of new horizontal wells to be drilled in any area can be predicted during early prognosis given the values of average reservoir permeability, well length, and fluid properties. This study can be used as a benchmark for the development of a thin oil column with a large and expanding gas cap under crestal gas injection using both vertical and horizontal wells.
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