The paper describes a practical case of using multi-well pressure Pulse-Code Testing (PCT) for assessment of inter-well connectivity and potential reserves for placement of new wells in off-shore environment. The study was based around two PCT cells (one calibration and one scanning) which were surveyed on the same platform within one month. The calibration PCT cell was set around injectors in peripheral area to eliminate the uncertainty in reservoir saturation, and provided estimation of macroscopic reservoir permeability (ka) and macroscopic rock compressibility (cr) in cross-well intervals. The reservoir permeability was found to be in good correlation with core-calibrated log prediction, while rock compressibility turned out to be twice higher than expected. Additionally, the calibration PCT cell picked the seismic fault as being impermeable and provided accurate values of its proximity to the pulsing well and its extension in the north direction. The sealing nature of this fault explains poor aquifer support in the southwest of the field. The acquired information helped to improve matching of formation pressure in the dynamic model. The scanning PCT cells identified the baffle in the southern part of the field, which was later interpreted as the bank failure of the meandering river flow. The study concluded that injection in river bedding is detrimental to uniform water flood pattern and should be avoided. The vertical sweep efficiency from PCT study was varying in different directions and helped to calibrate facies distribution and shale breaks. Some wells showed anomalous PCT behavior and were suspected of water production from thief zones, which was later picked by advanced production logging, based on spectral noise logs and temperature modelling. The fine-grid 3D model was calibrated both on static and dynamic data including the newly acquired framework of PCT and advanced production logging. The analysis of the new model has located the areas of low mobility oil due to poor communication between injectors and producers in these areas. These areas were recommended for infill drilling as well as for rearranging the water injection pattern to improve the sweep and pressure support pattern. The production and water cut of the newly drilled horizontal well showed a good match with the calibrated model prediction.
Chemical flooding is one of the enhanced oil recovery (EOR) methods to mobilize the residual oil after waterflooding by reduction of oil-water interfacial tension or wettability alteration and consequently increase of capillary number. The objective of this study is to assess the potential of alkaline surfactant (AS) flooding on a major oil reservoir at offshore Malaysia, besides to conduct the uncertainty assessment. High capital and operating expenditure are associated with chemical EOR (CEOR) projects. Therefore, key subsurface uncertainties quantified thoroughly for a robust assessment of influential parameters. The considered field is planned to be a pioneer in offshore CEOR. After the completion of pilot and matching the results in the simulation model, the key step is to upscale the results to the full field level. A critical step of the chemical EOR is to find the relative contribution of the influential parameters on the objective function like oil recovery. To do so, a detailed modeling work was performed for sensitivity and uncertainty analysis of AS flooding. Some of the important parameters used in the model are interfacial tension, chemical adsorption, slug size, and reduction of residual oil saturation by chemical. A single well pilot test project was successfully conducted in 2007. The pilot entailed the injection of Alkaline-Surfactant chemicals and chemical tracer test into a waterflooded reservoir and produced from the same well. The pilot test indicated significant reduction of residual oil saturation (Sorw) in the range of 50% to 80% of Sorw. After running the uncertainty cases for the targeted reservoir, the probability ranges of the objective function were established. Based on the results of this uncertainty analysis, a proxy model has been built and subsequently quality checked to ensure that it can reproduce the simulated data with high accuracy. The developed proxy model was used to capture all combination of parameter ranges and do better decision making on the project. The results showed that based on the corresponding ranges of parameters, the residual oil reduction and slug size exhibited the highest and lowest impact on oil recovery, respectively. Therefore, the uncertainty of the objective function can be reduced by mitigating the uncertainty of the most influential parameters. Moreover, this work presents a proper workflow of CEOR modeling in addition to detailed and systematic approach for uncertainty evaluation.
Data acquisition remains one of the crucial activities to be consistently executed throughout field life for any oilfield development. Significant operating expenditure (OPEX) is allocated each year to understand reservoir performance, thus reduce uncertainties and enable optimizations. This paper aims to highlight the issues faced during simulation model history matching (HM) process of a waterflood reservoir, including understanding of depositional environment and production data integrity. The output is utilized to improve recovery factor (RF) via infill opportunities and water injection optimization. Field A has run a second shot of 3D seismic in 2006 (first in 1995) and processed into a time lapse, 4D seismic. In 2014, a cased hole logging campaign utilizing the high precision temperature, spectral noise logging (HPT-SNL) tool has been completed to check the integrity and flow contribution of 12 wells in Reservoir-X. Within the same period, a pulse pressure testing (PPT) was carried out to verify the communication between wells, in addition to acquiring regular surveillance data which helped to improve reservoir simulation study. The 4D seismic helped to understand the areal waterflood front movement and explained the water cut trend anomaly in an updip well which experienced earlier water breakthrough than near downdip producers. Moreover, it helped to identify a bypass oil zone which can potentially be an infill location. As most of the wells are on dual string completion, the HPT-SNL campaign helped to improve production allocation of multi stacked reservoirs as well as identify problematic wells which required rectification jobs. The PPT assisted in identifying a baffle zone to explain the poor pressure support observed in some producers in the south from the nearby water injectors. All data interpretations were incorporated into final HM model which subsequently identified infill locations and the reservoir management plan (RMP) was successfully revised. An infill program was executed in 2015, which successfully secured additional EUR of ~9 MMstb. Based on the studies and outcome of the infill campaign water injection optimization helped to improve production and added ~2 MMstb reserves, through voidage replacement ratio (VRR) optimization and oil producer (OP) to water injector (WI) conversion. With these efforts, team could successfully project RF of >55%. This case study demonstrates how acquiring focused surveillance data and their effective integration in performance analysis in simulation study helps to reduce uncertainties, unveils infill opportunities, improves production injection optimization and thus helps to improve the recovery factor in brown fields.
PNPR cluster consists of three fields, namely PX, NX and PR (combined STOIIP ~200 MMstb), located ~300 km offshore of Peninsular Malaysia. Throughout its journey of monetizing marginal waxy crude, many challenges and hurdles have arisen, including sustaining oil production rate above economic threshold, pipeline clogging, and FPSO fuel uncertainties, which requires collaboration between surface and subsurface team to develop unique solutions in managing these downturns. Critically, PNPR cluster is expected to reach economic limit within few years’ time. This paper will elaborate on how IOR is achieved in PNPR cluster, historically and in near future. Ever since first production by PX and NX in 2004, infill drilling campaigns have been needed to sustain production above the economic limit of 5,000 bopd. Later in 2009, approximately a year after PR kicked off its first oil; the14 km pipeline to FPSO was plugged due to wax accumulation as a result of prolonged shutdown. A pipeline restoration project was embarked on involving installation of pipe in pipe (PiP), which utilizes hot water circulation as pipeline heating element. Another complexity has been consistently supplying gas to the FPSO for fuel, which involves a cement packer and adding perforation jobs in gas wells. Additionally, the waxy crude in these fields requires gas lift to be produced, particularly after water production started to escalate. This gives an opportunity to introduce through tubing electrical submersible pump (TTESP) to the field, while reducing dependence on gas lift. Financial wise, cost optimization initiatives are necessary to maintain the operability of the fields. To date, five infill projects have been successfully completed, contributing to IOR by bouncing back PNPR oil production rate. Additionally, a gas cap blow down (GCBD) from NX J80 reservoir also managed to improve reservoir recovery factor (RF) while supplying additional gas for fuel. Meanwhile, the PiP system, an enabler for IOR, has successfully ensures smooth crude oil delivery above pour point temperature from PR Platform to FPSO. In terms of gas fuel supply forecast, proper gas wells production phasing is planned to secure steady supply until 2023. IOR through artificial lift, TTESP is planned to be executed soon in one idle production well with potential gain of 500 bopd, hence eliminating option to workover the well, which is costly. Viewing IOR from economic standpoint, operating expenditure (OPEX) reduction through new philosophies were implemented, including reduction of FPSO charting rate, proactive maintenance and low-cost chemical bull heading, resulting in better cash flow for PNPR. It is expected that existing PNPR wells can recover 2 MMstb of oil through extension of economic life via incoming infill drilling in 2021, translating into 1-2% increase from current RF. Moreover, PX and NX already produced ~80% more reserves than originally booked in the first FDP.
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