Field A begun water injection in 2016 via four water injector smart wells, which were equipped with Permanent Downhole Gauges and Inflow Control Valves. The water injection module was housed on a rented MOPU due to space limitation. Amidst the study to revamp the reservoir management plan, the team found multiple discrepancies in the reservoir zonal allocation dating back to start of injection. Inherently, this affects the Voidage Replacement Ratio tracking. Hence, the question remains: How efficient is the water injection in Field A? As Field A injects from a rented facility, the long term RMP strongly influences annual OPEX. This paper explains the journey of reallocating Field A water injection volumes from 2016 until today, and how it affects the outcome of the RMP study. PETRONAS has an offshore monitoring system which visualizes historical pressure and temperature trends at any tagged equipment. Field A water injectors consists of multi-zones completed with ICVs and PDGs. ICVs allow choking and zone changes to happen without intervention, and PDGs show downhole pressure and temperature changes over time. Coupled with the manual database which tracks ICV changes and water injection rates, the team re-modelled the injected volume allocation changes to each zone by anchoring the model on PDG trends, ICV size and choke coefficient, and water injection rates via an advance nodal analysis software. For reservoir characteristics calibration, properties from past FBUS interpreted results were used as a basis. From the modelling journey, at the same injection scheme, results showed that zonal allocation with small PDG pressure changes of less than 5% during stable injection conditions does not significantly affect allocation ratio in the well. Overall, the allocation would change between 0 - 3% in total. As one of the objectives of the exercise was also to gauge expected injected volume allocation to a specific zone when there were obvious pressure changes but no records of changing ICV sizes, this could be achieved via a calibrated model. Once a good anchor was made on reservoir pressure, formation gas-oil ratio, permeability and skin, devoid periods in the past could be modelled for expected ICV sizes by varying the choke size openings till the pressure differential between tubing and annulus pressure was achieved. Hence, modelling the expected zonal allocation during that period. This improved VRR tracking for the injection reservoirs and aided to in the efforts to revamp the reservoir management plan. This paper will explain the lessons learnt of having proper surveillance data as the impact on long term reservoir management plan is significant. In future, fields with smart wells but disorganized data can utilize this alternate method to reallocate production/injection volumes without the need for intervention.
Multiphase flow meters (MPFM) have been known save costs for new installations, are compact and as effective as a test separator. Field "F" is a green field with 2 wells and has been producing since 2018 from the same reservoir. The test facilities consist of an MPFM, and F flows to a hub called Field "G". Towards Q2 of 2019, there was a significant increase in production rates from both wells without any changes to surface choke size and without enhancement jobs performed. Added to that, reservoir pressure showed steady depletion. Daily production allocation for F showed lower than usual reconciliation factor when combined with G hub production. This suboptimal allocation raised doubts about the MPFM well test readings which launched a full investigation into the accuracy of the meter. From the offshore remote monitoring system, the first suspect was the increased inlet pressure causing parameters to be out of the MPFM operating envelope range. However, after further checking, there were other pressing issues such as faulty transmitter, and low range sensors. As these issues were being dealt with amidst the COVID-19 pandemic, the process to fix the meter was longer than usual. Rectification involved troubleshooting the MPFM post performing Multi Rate Tests, back allocation check to hub production and PROSPER/GAP model matching to check on the credibility of the well tests. These efforts were made due to budget cuts, as there was no advantage to bring onboard an entire well test package (separator) to test the F wells. Post several rectifications, the liquid, gas and oil rates were within 10% difference from allocation meter back allocation and PROSPER model calculation. Reconciliation factor for field G has also increased to normal range of 0.92 to 0.95. However, the rectification also showed a significant drop in metered rates, proving that the MPFM was indeed generating incorrect well tests since Q2 2019. The drop was higher than 30% in gross production rates which lead to a better understanding of the reservoir, and corrections to be made to dynamic models for any future development projects. This hence proves that even with the similar reservoir properties in both wells, the MPFM well tests still require vigorous checking and should not be treated in the same way as a test separator. This paper will describe the efforts by surface and subsurface faculties to ensure the quality of well tests from the MPFM. For future projects considering the MPFM installation, best to frequently quality check the MPFM well test figures with a test separator. However, if that option is not feasible, the efforts in this paper can act as a guide for the field.
Production Enhancement (PE) opportunities in a 30 years-old Field D in Balingian province, offshore of Sarawak, Malaysia are dwindling. Behind casing opportunities (BCO) in relation to bypassed pay with good reservoir properties are either already perforated and produced or too costly and complex to be executed due to well issues. An in-house evaluation tool, Resolution Enhanced Modelling (REM), was developed by PETRONAS Petrophysics Department to evaluate and characterize thin beds or laminations. These Low-Resistivity-Low-Contrast (LRLC) sands are commonly bypassed as conventional logging tools cannot resolve their true parametric values and the apparent log responses across these zones appeared as shaly sand. By running REM across these intervals, the properties of the thin sands can be properly characterized, improving the net pay and economics of perforating and producing these reservoirs. In addition, a Rock Type (RT) based technique was used to evaluate some LRLC candidates in Field D. REM was run on LRLC sections in idle wells to evaluate their potential. To derisk and test the methodology, Well A3 with relatively more promising results was chosen as the first well to be perforated. Moreover, both strings of Well A3 were idle which makes it operationally easier to carry out the perforation job. From the initial analysis, the LRLC intervals in Well A3 could contribute to additional reserves of 0.3 MMstb with start rate of 300 bopd. The job required usage of barge assisted coiled tubing to pump cement and shut off existing high watercut zone and slickline to perforate through tubing. The actual job duration was prolonged from 30 days to 50 days due to monsoon season, driving the cost up to twice the planned amount. Post perforation, the initial oil rate was tested to be 500 bopd. After increasing the choke size, the well could flow at 800 bopd. Convinced by the success of Well A3, the same methodology was applied to Well C8 located at the north side of the field. Well C8 encountered operational difficulties such as lower than expected top of cement and perforation gun malfunction, resulting in only 54% of the proposed depth being perforated. Well C8 produced high gas, with initial well test rate of 10 bopd. Managing a brownfield where the easy oil is mostly exhausted can be challenging. Therefore, the team has to be more creative in unlocking the remaining oil and prolonging the life of a well. By using REM, the overlooked potentials hidden in LRLC sands can be accurately estimated, making the economics to perforate them more attractive to pursue.
Managing a 47-year brownfield, offshore Sarawak, with thin remaining oil rims has been a great challenge. The dynamic oil rim movement has remained as a key subsurface uncertainty especially with the commencing of redevelopment project. A Reservoir, Well and Facilities Management (RWFM) plan was detailed out to further optimize the development decisions. This paper is a continuation from SPE-174638-MS and outlines the outcome of the RWFM plan and the results’ impact towards the development decisions, such as infill well placement and gas/water injection scheme optimization. Key decisions impact by the RWFM findings are highlighted. One of the RWFM plans is oil rim monitoring through saturation logging to locate the current gas-oil contact (GOC) and oil-water contact (OWC). Cased-hole saturation logs were acquired at the identified observation-wells across the reservoir to map time-lapse oil rim movement and its thickness distribution. Pressure monitoring with regular static pressure gradient surveys (SGS) as well as production data, helped to understand the balance of aquifer strength between the Eastern and Western flanks. Data acquisition opportunity during infill drilling were also fully utilized to collect more solid evidences on oil rim positions, where extensive data acquisition program, including conventional open-hole log, wireline pressure test, formation pressure while drilling (FPWD) and reservoir mapping-while-drilling, were implemented. The timely collection, analysis and assimilation of data helped the team to re-strategize the development / reservoir management plans, through the following major activities: Re-strategizing water and gas injection plan to balance back oil rim between the Eastern and Western flanks, through deferment of drilling water injectors, optimization of water and gas injectors location and completion strategies due to stronger aquifer encroachment from east and south east.Optimizing infill wells drainage points where 2 wells were relocated based on cased-hole logs, as the first well original location was swept and the second well was successfully navigated through the oil rim using reservoir mapping-while-drilling techniques coupled with cased-hole log results. This resulted in securing an oil gain of 4000 BOPD from these 2 wells.Optimizing infill wells location and planning an additional infill well with potential additional oil gain of approximately 2000 BOPD.The understanding of current contact and aquifer strength from the surveillance data assisted in identifying fit-for-purpose technology for the new wells such as the application of viscosity-based autonomous inflow control device which assisted in placing the well closer to GOC due to the observed rapid rising of water table, this will help sustaining the well life. This paper highlights the importance of data integration from geological knowledge, production history, reservoir understanding and monitoring through regular SGS and time-lapse cased-hole saturation logging, coupled with extensive data acquisition during infill drilling. By analyzing and integrating the acquired data, project team can then confidently re-strategize and successfully execute the complex mature oil-rim brownfield redevelopment.
Mature Field-D has produced at recovery factor (RF) less than 20% due to its geological complexity. As per re-development plan, four wells were drilled from newly built platform in 2020. Each well was completed with combination of oil and gas zones with maximum five zones per well. The gas zone is utilized as an in-situ gas lift, considering gas lift gas shortage and anticipated future requirement for artificial lift upon pressure depletion and water breakthrough. All-electrical inflow control valve (ICV) and permanent downhole gauges (PDG) has been installed across each respective oil & gas zone. The system serves to provide zonal production control to mitigate high producing gas-oil-ratio (GOR) or water breakthrough zones. Single string multi-zone ICV completion enables maximum production from layers with varying reservoir properties and pressure depletion. In addition, gas zones completed with ICV enables cost-effective application of in-situ or well-to-well gaslift, facilitates future non-associated gas production for gas monetization project as well as gascap blowdown opportunities. Application of all-electric smart completion has enhanced proactive surveillance and provided greater production control flexibility resulting in higher production than target. From the downhole data obtained from PDG, wells and network model were updated with good certainty and used to further optimize production at well, platform and field level. Multiple ICV configuration were simulated to maximize oil, minimize gas and water production considering facilities limitation in terms of liquid handling and gas processing to reduce carbon footprint. The gas zones have been utilized for in-situ gas lift using ICV. The smart completion has also enabled efficient unloading facilitated by real-time data acquisition and production control through ICVs leading to additional cost savings. It marks the first installation of an all-electric smart completions offshore Malaysia and Asia Pacific. This paper will explain the functionality of all-electric ICV system and outlines the methodology undertaken to optimize production at well, platform and field level utilizing industry recognized well and network models.
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