An Approach for Production Enhancement Opportunities in a Brownfield Redevelopment Plan (Russian)
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A revised Field Development Plan (FDP) for Betty Field was prepared based on a process that was simultaneously sensitive to reservoir and operational constraints and uncertainties. This so called "Optioneering" process was an iterative, multidisciplinary optimization task that generated an action plan based on multiple options developed by reservoir, production, drilling and facilities engineering and ranked by economics. The process specifically involved first generating a series of unconstrained production options, which then considered drilling reach and anti-collision limitations, and finally had the appropriate facilities and regional evacuation constraints imposed. To achieve this, history-matched numerical reservoir models were first run within the framework of an infill well-location optimization software package. Then, drilling constraints were imposed with drilling planning software and facility constraints were included via a surface coupling system for multiple-reservoir models. Uncertainties in the reservoir characteristics and in the facilities/evacuation schemes were addressed by quantifying their impact on the ultimate recovery efficiency. During the optioneering exercise, more than 100 unconstrained options for seventeen stacked reservoirs were identified from the perspective of infill drilling, pressure maintenance by gas injection and/or waterflooding, high pressure gas production, horizontal wells and production enhancement work. Based on typical costs and economic rank, the high potential unconstrained production options for each reservoir were determined. After imposing the drilling constraints, all reservoirs were then coupled to account for surface facility constraints. In the final analysis, five sidetrack wells reaching 12 new drainage points (NDP) over 10 reservoirs were designed. This infill drilling scheme will increase current reserves by 128%. Furthermore, a gas injection scheme identified as the optimum plan for A6.0 reservoir will increase current reserves by 28%. Field wide recovery factor will be improved by 9%. Introduction Oilfield development and management decisions are usually made under high risk and uncertain conditions that stem from both surface and subsurface unknowns. The optimized field and reservoir management can be achieved through successful uncertainty management. Uncertainty management has two main aspects: minimizing uncertainty followed by estimating risks from remaining uncertainty. Minimizing uncertainty reduces the risks and improves project economics. Uncertainty can be managed by integrating multi-discipline multi-scale data and utilizing 3-D numerical models as predictive tools. Then, estimating risk from the remaining uncertainty allows us to make informed investment decisions. An ideal FDP should not only include recommendations for an optimum development strategy with its implementation plan, but the estimated risks involved in executing the proposed plan. So the ideal plan would have two parts: optimization and risk assessment, which are also interrelated. However, ranking and screening of options for the plan should be done only after taking the risk factors into account. Therefore, an iterative procedure is required which generally converges after several iterations. Converging to an optimized field plan involves identifying the best suited activity, and then designing that activity to its optimum level. Final risk exposures for the selected activity are estimated and reported, whereby potentially high risk aspects are known to the implementation team and accounted for in economic evaluations. Generating options, and screening them to achieve an optimum FDP with its associated risks requires an optioneering process.
A revised Field Development Plan (FDP) for Betty Field was prepared based on a process that was simultaneously sensitive to reservoir and operational constraints and uncertainties. This so called "Optioneering" process was an iterative, multidisciplinary optimization task that generated an action plan based on multiple options developed by reservoir, production, drilling and facilities engineering and ranked by economics. The process specifically involved first generating a series of unconstrained production options, which then considered drilling reach and anti-collision limitations, and finally had the appropriate facilities and regional evacuation constraints imposed. To achieve this, history-matched numerical reservoir models were first run within the framework of an infill well-location optimization software package. Then, drilling constraints were imposed with drilling planning software and facility constraints were included via a surface coupling system for multiple-reservoir models. Uncertainties in the reservoir characteristics and in the facilities/evacuation schemes were addressed by quantifying their impact on the ultimate recovery efficiency. During the optioneering exercise, more than 100 unconstrained options for seventeen stacked reservoirs were identified from the perspective of infill drilling, pressure maintenance by gas injection and/or waterflooding, high pressure gas production, horizontal wells and production enhancement work. Based on typical costs and economic rank, the high potential unconstrained production options for each reservoir were determined. After imposing the drilling constraints, all reservoirs were then coupled to account for surface facility constraints. In the final analysis, five sidetrack wells reaching 12 new drainage points (NDP) over 10 reservoirs were designed. This infill drilling scheme will increase current reserves by 128%. Furthermore, a gas injection scheme identified as the optimum plan for A6.0 reservoir will increase current reserves by 28%. Field wide recovery factor will be improved by 9%. Introduction Oilfield development and management decisions are usually made under high risk and uncertain conditions that stem from both surface and subsurface unknowns. The optimized field and reservoir management can be achieved through successful uncertainty management. Uncertainty management has two main aspects: minimizing uncertainty followed by estimating risks from remaining uncertainty. Minimizing uncertainty reduces the risks and improves project economics. Uncertainty can be managed by integrating multi-discipline multi-scale data and utilizing 3-D numerical models as predictive tools. Then, estimating risk from the remaining uncertainty allows us to make informed investment decisions. An ideal FDP should not only include recommendations for an optimum development strategy with its implementation plan, but the estimated risks involved in executing the proposed plan. So the ideal plan would have two parts: optimization and risk assessment, which are also interrelated. However, ranking and screening of options for the plan should be done only after taking the risk factors into account. Therefore, an iterative procedure is required which generally converges after several iterations. Converging to an optimized field plan involves identifying the best suited activity, and then designing that activity to its optimum level. Final risk exposures for the selected activity are estimated and reported, whereby potentially high risk aspects are known to the implementation team and accounted for in economic evaluations. Generating options, and screening them to achieve an optimum FDP with its associated risks requires an optioneering process.
Water-Shutoff Treatment in Wells With Single-String Multizone Completion Intervals (Brownfields)
Due to the stacked nature of reservoirs in the Niger Delta, the predominant completion types are dual-string multizone and single-string multi-zone completions. These designs have been adopted to reduce the number of infill wells required for field development. However, they come with a disadvantage in regard to carrying out a successful intervention when water break through occurs. Water breakthrough and high basic sediments and water (BS&W) are problems associated with fields having strong aquifer drive mechanisms. As a result, most exploration and production companies have learned to manage water production up to a tolerable limit, which is dependent on the water handling capacity of the installed facilities and also the economic cutoff limits for the wells in question. The reason for this type of water management is the lack of confidence in the water shutoff remedial operations. From a survey carried out in the early 90s, it was estimated that only 35% success was achieved worldwide in water shutoff remediation. This low success rate is due to poor diagnosis, wrong selection of water shutoff solutions, and how complicated the well completion is with respect to the zone of interest to be treated. Field X, 1, 2, which consists of a large gas cap and a 100-ft total vertical depth (TVD) oil column, was developed with the single-string multizone completion design. Due to the presence of a strong aquifer in this field, water production started early and some of the wells were shut-in due to lift problems associated with the water production. A sidetrack option was considered as a means of bringing these wells back on production, but was not used because of the absence of a gas gathering facility for the field. As a result of production decline and lack of infill opportunities, cement-water shutoff and re-perforation intervention in the wells was adopted. The objective of the cement-water shutoff was to ensure that the perforations, which were flushed, were completely sealed off and isolated and subsequently re-perforated shallower. After slurry placement and squeezing, it is important to ensure that a good cement job has been performed. Operationally, the top of cement (TOC) is tagged using slick-line in a vertical or deviated well. If the TOC is not at the theoretical depth, then a top-up job is carried out with additional slurry. On the other hand, if the TOC is at the theoretical depth, then a pressure test is performed to confirm that the perforations are squeezed off. For intervals behind the sleeve as in the case of Field X, ascertaining the TOC is technically impossible because the perforations are behind the production tubing. For such single-string selective completions, only a pressure test can be performed to confirm that the perforations are squeezed off. This paper addresses the planning, operational and the learning from the through-tubing water shutoff campaign successfully carried out on wells with single-string multizone completions. Introduction Cement-water shutoff intervention behind the sleeve in multizone completions is a solution that is not common due to its low probability of success. Shell Petroleum Development Company Nigeria and Schlumberger successfully carried out this operation in four wells drilled and completed in Field X. The biggest issue associated with cement squeeze in a singlestring multizone completion is the difficulty associated with placement and confirming where the TOC would be after the intervention. This by implication makes it difficult to determine if a good cement job has been performed.
Casing-while-drilling (CWD) operations have become a well-known technology used to minimise drilling time and reduce AFE budget. PETRONAS has drilled several wells in Malaysia by using this technology, and it has proven to be a cost efficient strategy particularly in batch drilling process. Past CWD operational experiences have demonstrated stark differences when compared to conventional drilling in terms of wellbore surveying and formation evaluation. Weak and noisy signals from mud pulse telemetry were primary issues that required a significant amount of rig time when acquiring measurement-while-drilling (MWD) and logging-while-drilling (LWD) data. In fact, several significant challenges were encountered. First, the mud pulse signal which traverses from downhole (MWD) to the surface somehow dampened out. Although various types of mud pulse telemetry have been used, significant problems remain. In addition, the signal transmission worsened when seawater was used as the drilling fluid, resulting in nonproductive time due to provisioning ofchange out tools with different configurations for mitigation and trial-and-error purposes. Finally, overall drilling efficiency was reduced as a result of poor signal detection and capturing. EM-MWD used in combination with gyro-while-drilling (GWD) was identified for implementation when drilling four wells using Tesco CWD technology in the Erb West field. The mud pulse and electromagnetic telemetry systems were executed asa pair to compare captured signal strengths in the same environment, i.e., directional CWD with seawater drilling fluid. After drilling ceased, the generated results proved that EM-MWD is a viable technology that can be used to overcome signal attenuation issues in a CWD operation. It also minimise health, safety, and environment (HSE) risks as well as established a working model of EM-MWD-CWD. Most importantly, such application reduced rig time by 3.9 days which contributed to 26% of cost saving for the surface section drilling by having trouble free MWD signal detection and faster drilling operation.
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