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.
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 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.
The Bahrain Oil Field ("Bahrain Field"), wherein the first oil discovery was made in the Gulf region in 1932, is now in a mature stage of development. Mauddud is the major oil-producing reservoir in the Bahrain Field, situated in an anticlinal feature of the middle cretaceous period. This is a highly undersaturated, low-dip, layered, heavily faulted, and preferentially oil-wet reservoir. Crestal gas injection (GI) in Mauddud has continued to be the dominant drive mechanism since 1938, making it the first improved recovery project in the Arabian Gulf region. This paper summarizes the performance of nearly 84 years of gas injection in Mauddud reservoir. Performance-based analysis is carried out using different analytical techniques to determine voidage replacement and maximum gas-cap expansion rate to avoid gas overrunning and injection requirements. Volumetric sweep is estimated using volume of gas injected and gas cycled. Recovery is calculated based on material balance analysis using hydrocarbon pore volume (HCPV), gas injected, free gas-cap volume, and volume of residual oil in gas-cap (VOR). Semilog analysis of free gas/oil ratio (GOR) versus cumulative oil (Np) yields swept pore volume and moveable oil in different areas. Gas management strategy is devised based on wells to be shut-in, cut-off GOR, oil deferred, gas cycling limit, and remediation of high GOR wells with gas shut-off workovers. Optimum number of infill wells is evaluated based on NPV (net present value) for both vertical and horizontal completion. Gas injection gravity drainage is an efficient mechanism in the Mauddud reservoir. Based on gas expansion rate to avoid gas overrunning, maximum GI rate is 652 MMscf/D. The volumetric sweep by gas is around 80%, giving a 50% recovery in gas-invaded areas. Critical gravity drainage oil rate per well is 383 STB/D. The average cycling of gas was 60% initially during 1970's, declined to 50% during 1986 to 2000, and currently increased to over 80%. The cumulative gas cycling is around 70%. Areas B, D, G, and H have the highest remaining mobile oil and should be the focus for infill drilling. A GOR cut-off of 80,000 scf/STB involves 97 wells, resulting in a gas reduction of 200 MMscf/D and an oil rate of 1,600 STB/D. A curtailment of free gas production of 100 MMscf/D will reduce the gas cycling from 87% to 70%. Cased hole horizontal well trial is promising based on workovers of open-hole horizontal well and newly drilled horizontal well trial with cemented liner. The development of Mauddud with a mix of both deviated/vertical and horizontal wells will reduce the number of wells in the tight spacing drilling campaign and provide robust economics. The methodology and analytical techniques described in this paper can be used for performance-based analysis of a large immiscible gas injection project.
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.
The Mauddud reservoir discovered in 1932 in Bahrain is now in a mature stage of development. Crestal gas injection (GI) in the oil bearing, under saturated, layered, and heavily faulted carbonate reservoir has continued to be the dominant drive mechanism since 1938. Current strategy for maximizing reservoir potential and reduce production decline with infill drilling, workovers, and routine maintenance of wells are not adequate for a matured reservoir like Mauddud. As such, a detailed feasibility study is being carried out to identify the most appropriate enhanced oil recovery (EOR) process for this reservoir and define a strategy for further evaluation and implementation of the most promising EOR options. This paper aims to present detailed design and results of laboratory experiments using CO2 and ethane gas en route to sector modeling studies in three (3) selected large areas. A high-level cost estimate is also performed using the results from the pattern simulations. The gas EOR laboratory study consisted of performing swelling and slim tube tests using the recombined Mauddud live oil and two injection gases: carbon dioxide (CO2) and ethane (C2). The swelling tests and the corresponding constant composition experiments (CCE) were matched using a 16-component equation of state (EOS) model. Slim tube simulations performed with the tuned EOS were able to replicate the oil recovery values from the slim tube tests. Representative sector and pattern simulation models were developed to estimate the EOR production potential from the Mauddud reservoir. The sector model developed was calibrated to the historical production, injection, and pressure data. An extensive sensitivity study was conducted to match the fluid flow dynamics of the reservoir. The history matched sector model was used to select and develop pattern simulation models that were used to estimated EOR production potential. Swelling tests conducted with CO2 and Ethane shows the effect of oil swelling and changes in oil properties such as density, viscosity, formation volume factor, and solution GOR. The elevation in swelling factors and the reduction in oil viscosity exhibit the benefits of using CO2 and ethane as injection sources for Mauddud. Solid precipitation on the PVT cell window was observed, indicating the possibility of asphaltene precipitation with CO2 and C2 injection. CO2 slim tube tests showed a minimum miscibility pressure (MMP) of about 1,762 psig, which is around 800 psi higher than the current reservoir pressure. Therefore, CO2 injection under miscible conditions is not viable in Mauddud reservoir. Ethane gas mixture and Mauddud reservoir live oil showed an MMP of 1,022 psig. Ethane pattern simulations showed incremental oil recovery factors over the no-further-activities (NFA) between 17.7 and 27.6 percent of the original oil-in-place (OOIP). The laboratory and sector simulation results are crucial to explore the feasibility of any EOR project and will serve as inputs to detailed economic evaluation as well as pilot design and facilities planning.
One of the key uncertainties that impacts reservoir development and waterflood performance in a thick reservoir is vertical transmissibility across the stylolitic intervals. It is not clearly understood whether low vertical permeability or negative capillary pressure across stylolites holds the water from slumping, because both the realizations could achieve good history matches of observed well performances (water cut and pressure except MDT/RFT) in the simulation model. It is, therefore, crucial to calibrate the simulation model using field test results before it can be used to produce a reliable forecast. A comprehensive dualwell vertical interference testing program using a singleprobe formation tester was designed 1 and implemented in a stratified carbonate reservoir in Upper Zakum Field. This paper presents the results of a time-lapsed dual-well vertical interference test that enabled assessment of the degree of vertical communication across various sub-zones and quantification of in-situ vertical permeability on a reservoir scale.The testing procedure involves a partial penetration well test followed by the generation of a pressure wave by a partially penetrating well which is monitored in an offset, fully penetrating well via time lapse MDT measurements. Upon completion of the inter-well interference test, a vertical interference test is conducted in the observer well by using a dual-packer, dual-probe MDT tool.Analytic methods were initially utilized followed by construction of a 3D numerical sector model to match the observed data in order to estimate vertical permeability. Results indicate that there are no vertical permeability barriers present except in the bottom part of the reservoir that could account for the water over-ride of oil seen in the test well. Thus, low vertical permeability is discounted and presumably, capillary pressure barriers may be responsible for preventing slumping of injected water within the reservoir. This finding will have a significant impact upon future field development planning particularly with regard to well design (orientation, location and benefit of lateralisation). More importantly, the results can be utilized to calibrate the full field model culminating in a credible dynamic simulation model to produce accurate future prediction cases.
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