Managing complex brownfield production and sustainability expectations has become a norm in the oil and gas industry – where opportunities to materialize resources can still be present. This paper covers the constructive practices in Field B, a 50-year-old brownfield offshore Malaysia in understanding uneven fluid movements dynamics via execution of time-lapse data acquisitions to justify planning for infill drilling. This has led to successful four (4) horizontal geosteering well placement in the major oil reservoir units. Time-lapse contact monitoring was made possible through integration of recent open-hole, production, dynamic simulations & cased-hole saturation logs in Reservoir A. Between the year 2014 to 2021, saturation logging campaigns were executed, and phenomena of uneven fluid contacts was observed between the un-faulted western to eastern areas of the field. Eastern area wells have observed shallower gas-oil contact (GOC) and oil-water contact (OWC) by 80 to 100ft-TVD, resultant from gas and water injections, disproportionate production withdrawal, potential gas leaks behind casing and stronger aquifer strength. The combination scenarios of geological structure and fluid contact uncertainties provided a range to drive geosteering pre-job modelling planning to sensitize multiple cases to optimize the well trajectories. The integrated ranges of current contact derived from saturation logs, recent open-hole logs and reservoir simulation constructed the basis of low-base-high remaining oil opportunity cases for planning and economic evaluations. Coupled with advancement of frontier technology Geosteering-HD, four (4) wells successfully penetrated 35 to 80ft-TVD of oil column in horizontal section and maintained along 1500-2000ft-AHD. Tilted oil-water OWC was observed in three (3) of the wells located at eastern area, where the OWC trends shallower from the heel to toe of the horizontal portion confirming the results from time-lapse contact information and contacts prediction from reservoir model. The other well drilled at western area, observed a mostly flat OWC throughout the horizontal section with slight tilting towards the toe, reflecting weaker aquifer strength at the western flank as observed in recent cased hole and open hole logging. The fluid contacts and structure penetrated in all four (4) wells are within the predicted low-base-high cases from pre-job modelling, leading to an optimum placement of horizonal well in the oil column. These optimizations have led to a successful infill campaign, delivering higher production rates of 5,600BOPD against planned 4,600BOPD for brownfield reserves acceleration. All data acquisition needs to be exhaustively studied and managed as each holds an important piece of evidence on what the field tries to express. In this field, the timely execution of time-lapse cased-hole logs integrated with open-hole results were vital and principal driver in de-risking fluid contact uncertainties within eastern and western area prior infill drilling for a successful horizontal well campaign.
The horizontal wells within the context of this case study are located offshore Malaysia, where the reservoirs vary in grain size and quality. The infill wells include 3 oil producer wells targeting S reservoir and 1 horizontal sidetrack well targeting R1-R3 subunit reservoirs. The horizontal wells’ objective is to optimize minimum lateral length of 1,000-2,000ft MD at 1/3 vertical standoff from GOC within the target oil column. Based on recent data from offset wells, the fluid contacts (GOC and OWC) remained uncertain, hence well placement within the target oil column becomes the main challenge. The wells are expected to have low resistivity contrast between oil and water composition. In this kind of reservoir environment, the standard reservoir mapping tool may not be sufficient for differentiating reservoir fluid properties of oil and water bearing formation. For such challenging condition, an integrated real-time well placement technology, high tier triple-combo logs, Neutron Near- Far count and Formation Sigma measurements were deployed to fully achieve drilling objectives. 3 horizontal wells with 1 horizontal sidetrack well were successfully executed within the target zone, achieving objectives beyond expectation. A new generation of LWD tool including high-definition reservoir mapping-while-drilling technology with advanced inversion was deployed to fulfill geosteering requirements. The workflow presented in this project is a synergized scope of multi-domain, from both drilling and subsurface. This case study demonstrated the value of high-definition reservoir scale mapping technology. It provides an innovative and deterministic method to identify low resistivity low contrast boundaries of oil from transitional water zone which was difficult to be achieved by conventional reservoir mapping tool. At the landing section, the high-definition tool helped to reveal clearly OWC below the tool with greater confidence compared to the standard tool. The information from the high-definition tool, paired with the fluid identification offered from Neutron-Density and Neutron Near- Far count together were essential for an accurate landing. The usage of reservoir scale mapping technology in the horizontal section revealed the tilted OWC and reservoir structure at the same time, which allowed the team to achieve the required minimum production length while maintaining required standoff from the OWC. All wells were geosteered successfully with the accomplishment of placing the trajectories in optimum positions despite having a tight TVD window.
Wells 1A, 2A, 3A & 4A are designed as four (4) horizontal oil producers to maximize the oil recovery from the XXYY heterogenous sandstone reservoir in Offshore Malaysia. The reservoir has been producing since 1975 on natural depletion before gas injection (1994) and water injection (2019-2022) were introduced. XXYY reservoir is expected to have wide permeabilities ranges from as low as 1-mD to 4-D and high uncertainty of gas-oil contacts from recent saturation logging acquisition. Coupled with the complex reservoir nature of massive gas cap and thinning oil rim observed between 30-50ft-TVD, historical production of oil with optimum GOR in XXYY reservoir remained the main challenge towards late field life. For such challenging condition, pre-planning with multiple Autonomous Inflow Control Device (AICD) valve placement scenarios across the horizontal sections were analyzed using integration of reservoir and well models for valves optimization process to achieve well's target production and reserves by the end of PSC. Specific drawdown and production targets were set as critical design limits in managing sanding and erosional risks while still achieving production target. Ultimately, these models provided both instantaneous and long-term forecasts of AICD impact on the wells’ performance – key factors in the final design. The workflow presented in this project synergized scope of multi-domain from subsurface, completion and drilling. This case study demonstrates the value of detailed design steps on AICD placement across horizontal segments and optimizations based on actual open-hole logging interpretation, mainly – permeability, saturation and vertical stand-offs from gas-oil and oil-water contacts. The horizontal wells drilled are susceptible to "heel-toe" effect, resulting in dominant production in the heel section while the toe section contributes less, subsequently inducing gas coning at the heel. XXYY reservoir is also sand prone and requires sand control. For these reasons, all 4 wells are designed to be completed with Open Hole Stand Alone Screen (OHSAS) with the use of AICD to balance production withdrawal across the horizontal segments and provide GOR control. The four (4) wells penetrated 30-60ft-TVD of oil column with 10-15ft-TVD vertical stand-offs from gas-oil contact (GOC) to maintain a 2/3 column ratio from oil-water contact. Given these marginal stand-offs to GOC, integration of AICD sensitivities workflow were performed on-the-fly to analyze instantaneous and time-stepped oil and GOR rates allowing the team to achieve required production sustenance. The installations of optimized AICD have resulted in successful GOR control below 6 Mscf/stb targeted, resulting in delivering higher instantaneous production rates against planned of 4,600bopd. The success of AICD optimizations integrated with OHSAS completion, reservoir mapping and petrophysical evaluation have been proven as ultimate solution to deliver the wells oil production for a brown field rejuvenation project. The pre-drill and post-drill results calibrated to actual well tests are compared for further sensitivity analysis, to be used in the continuous improvement of production management strategies in the field.
Well#1 was completed as horizontal oil producer with Openhole Stand-Alone Sandscreens (OHSAS) across a thin reservoir with average thickness of 20ft in Field B. The first Autonomous Inflow Control Device (AICD) in PETRONAS was installed to ensure balanced contribution across horizontal zones with permeability contrasts and to prevent early water and gas breakthrough. Integrated real-time reservoir mapping-while-drilling technology for well placement optimization combined with industry-leading inflow control simulator for AICD placement were opted. The early well tests post drilling showed promising results with production rate doubled the expected rate with no sand production, low water cut and lower Gas to Oil Ratio (GOR). Reservoir Management Plan (RMP) for this oil rim requires continuous gas injection into gas cap and water injection into aquifer. However, due to low gas injection uptime caused by prolonged injection facilities constraints, the well's watercut continued to increase steadily from 0% to 80% within a year of production despite prudent surveillance and controlling of production during injector's downtime. After the gas injection performance has improved, the well was beaned up as part of oil rim management for withdrawal balancing. Unfortunately, a month later, the production rate showed a sudden spike with significantly low wellhead pressure, followed by hairline leak on its choke valve and leak at Crude Oil Transfer Pump (COTP) recycle line. Sand analysis by particle size distribution (PSD) confirmed OHSAS failure, while the high gas rate from well test results confirmed AICD failure. A multidisciplinary investigation team was immediately formed to determine the root cause of the failure event. Root Cause Failure Analysis (RCFA) method was opted to determine the causes of failures, including the reanalyzing of the OHSAS and AICD completion design. The well operating strategy was also reviewed thoroughly by utilizing the well parameters trending provided in the Exceptional Based Surveillance (EBS) Process Information (PI) ProcessBook. Thorough RCFA concluded that frequent platform interruptions and improper well start-up practices have created abrupt pressure changes in the wellbore, which has likely destabilized the natural sand pack around the OHSAS and created frequent burst of sand influx across AICDs. The operating of a high gas-oil ratio (GOR) and high watercut sand prone well without pre-determined AICD sand erosion toleration envelope have also likely contributed to the failure of AICDs. The delay in detection of OHSAS failure in Well#1 due to ineffective sand monitoring method thus resulted in severe sand production which caused severe leak at its choke valve and COTP recycle line.
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.
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