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 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, a new cased-hole horizontal well drilled in 2021 is promising. 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.
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