The scope of the paper is to share a case study of a successful horizontal well completed within an extremely thin oil rim of ~10ft with bottom water. This paper highlights the differentiating activities undertaken to deliver the well despite the challenges of extremely thin oil rim, strong water drive and uneven current fluid contacts. Prior to drilling this well, attempt was made to mitigate the uncertainty regarding the current gas-oil contact (GOC) and oil-water contact (OWC) by carrying out cased-hole logging in some of the adjacent wells, and re-sequencing and re-optimizing the location of two of the wells targeting the reservoirs below. This obviated the need for the pilot hole and thereby resulted in a cost saving of ~USD 1Million. Furthermore, the dynamic simulation model was updated to create a fit-for-purpose model with the latest OWC and GOC, so as to be able to test various trajectories. While drilling, the well was drilled with real-time reservoir mapping-while-drilling technology and integrated with real-time reservoir characterization, fluid typing and trajectory modification, while maintaining Dog Leg Severity (DLS) below 3 deg/100ft for the ease of completion run. Completion was then optimized with viscosity-based inflow control orifices. Post drilling, dynamic and well models were calibrated to the actual results to determine optimum production rate for the well life. The horizontal well was successfully navigated and optimally placed in the extremely thin oil column. Tilted contacts were encountered in the targeted subunits where actual current contacts came in ~20ft shallower at heel and ~10ft deeper at toe compared to prognosis. Consequently, the heel landed at a 5ft stand-off from water, and the toe landed 18ft stand-off from water and 6ft stand-off from gas. The well was successfully unloaded and tested at a controlled oil rate of 2887 bopd, 50% higher than planned target. This paper presents the entire process from well planning until well production tie-in. This was achieved through the integration of subsurface understanding with the utilization of the appropriate technology. Finally, the management's trust in the capability of the team members ensured deliverability of the target production rate and the consequent booked reserves.
Managing an oil rim type reservoir has constantly been a great challenge and understanding the oil rim movement has remained as one of the main subsurface uncertainties. Prudent reservoir management through an active reservoir, well and facilities management (RWFM) plan is key to realizing the uncertainties, optimizing production and reserves of brownfields. Monitoring the oil rim through cased-hole reservoir saturation logging has been identified as a de-risking method, planned and executed for two consecutive years in the field to minimize the oil rim uncertainty. The field studied is one of the brownfields in offshore Sarawak, Malaysia, which has been on production for more than 40 years. Results acquired from the cased-hole logs have triggered the need to optimize the location of an infill oil producer planned in the Field Development Plan. The cased-hole results indicated that the original oil target in the N reservoir had mostly been swept by water. Through thorough studies and modeling, an opportunity to the western flank in M reservoir, located close to a proposed workover well, was suggested. Furthermore, latest input on the proposed workover well and facilities health check suggested the workover candidate was not favourable due to its location on an aging single well monopod structure with complex well mechanical problems. Thus, the planned infill oil producer was recommended to replace the workover well and recover the reserves. Integrated studies incorporated cased-hole results with reservoir modeling indicated that the new infill location would yield a total of 5.7MMSTB reserves with initial production rate of 1215BOPD. In addition, through integration of a multi-disciplinary team, revision to the infill location was timely and the infill was also accelerated from Phase II to Phase I of the development plan as a rig filler for cost optimization. Well test result successfully validated the reservoir productivity of 1238BOPD with no water production. This paper presents the integrated subsurface and surface solutions and criticality of proactive data acquisition, field monitoring and collaborative team work strategies to maximize the recovery from a brownfield.
Properly distributing injected fluid to provide injection conformance and reservoir pressure support into the respective zones of interest in mature fields can be challenging. This challenge, with injection fluid distribution, is typically encountered in fields with high contrast in permeability, reservoir pressure, and injectivity indexes among individual zones. Deployment of intelligent completion (IC) technology to address this challenge has rapidly increased, especially in multi-zone water injector wells, due to its capabilities for real-time reservoir monitoring and control of the fluid injected into multiple zones without requiring well interventions. This paper presents a case study of successful installation of IC technology in two water injector wells in Field B offshore Sarawak. The main objective of the IC implementation is to provide an efficient water-injection method for pressure support to the nearby oil producers and counteract the gas expansion through water injection at the flank area. Water injection implementation using the IC approach can further develop the oil rims and improve oil recovery in the particular reservoir to extend the field's production life. The custom tailored inflow control valve (ICV) design is robust enough to provide control of desired zonal injection rates. Each well was installed with two sets of ICVs to control the injection rate for each dedicated zone as well as a real-time permanent downhole gauge (PDG) to monitor the pressure drop across the ICV for zonal rates allocation / analysis. Apart from conceptual and detailed engineering study of the applied IC technology, proper downhole equipment selection and integration with surface facilities are also crucial to ensure successful implementation of the IC system as a holistic solution to achieve the injection objective. Post well completion installation, a water injectivity test was performed in both the selective and commingle injection modes. During selective injection testing, different positions of the ICV were manipulated and the water injection rate was monitored. This testing approach was performed for each ICV in the well. Post selective injection testing, commingle testing was conducted at the base 9,000 bwpd and maximum injection target of 18,000 bwpd, in which the testing was successfully executed to achieve the maximum well target injection rate. This paper shall discuss the reservoir management strategy through deployment of the water injectors, conceptual well completion design, and multi-zone injectivity requirements. Details such as ICV design using pre-drill and post-drill information, final well completion strategy, pre-installation preparation, installation optimization, execution of the IC deployment, injectivity test procedure, and results are discussed as well.
The perforation strategy of Dynamic Underbalance (DUB) created the surging effect to remove debris from the perforation tunnels, thus reducing skin for optimal injectivity in this offshore development water injector well in Malay Basin, Offshore Sarawak. The objective was to inject up to 18,000 bwpd for pressure maintenance purposes. In the design phase, perforation software was used to perform the simulation iterations by sensitizing on the number of empty tubing conveyed perforation (TCP) gun chambers added at the top and bottom of perforation intervals. However, due to small gun size (4-½ in.), limited rat hole length and high static underbalance (1,000 psig), the desired amount of DUB using conventional empty gun volume only was not possible to be achieved. As a result, an innovative approach using two Pressure Operated Tester Valves (POTV's) was proposed, to create additional empty space inside the tubular between the POTVs above the packer. However, this created additional challenges which had to be overcome. Presence of empty tubulars in between the POTVs prevented the required hydraulic pressure transmission through the tubulars to activate the perforation guns via normal hydraulic TCP firing head. Therefore, a specialized firing system was required, which consisted of an acoustic communication system triggering downhole electronics to actuate a standard TCP firing head (Top-Fire Dual) - a first for this type of firing head. The POTV was activated by applying a pre-set annular pressure. Opening lower POTV, after the perforation fired, will create the required DUB surge, around 1,000 psi, which help cleaning up the perforation tunnels. Downhole fast gauges (recording in microseconds range) were run as part of the assembly to measure and to confirm the created DUB effect. Both fast gauges as well as acoustic gauges confirmed that 300 psi DUB was created upon gun firing and around 1,000 psi surging was achieved after the two POTVs were opened. Maximum losses recorded at 525 gallons per minute were observed following perforation. The well's injectivity performance was evaluated by performing step rate test and the result confirmed the well was able to meet higher injection rate than the plan.
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