Various sand control completion techniques have been applied to address sand production issues in Field A. The sand production challenges are often aggravated with decreasing reservoir pressure and increasing water cut due to fields maturity. Conventional gravel pack methods such as circulation pack or high-rate water pack were effective and has high reliability in controlling sand production. However, these methods often resulted in high initial skin (subjected to gravel sizing, completion fluids, screen sizing, etc.) which affect the well productivity. For wells with fines migration issues, the skin will further build-up as the well produce over time. In addition, these sand control methods are associated with higher installation cost. In order to address these issues, Resin Sand Consolidation technique was successfully applied as primary sand control in Well 8 to prove its reliability, productivity, and cost effectiveness. It was the first application for a new development well in Field A and second in PETRONAS Carigali Sdn. Bhd. (PCSB) Malaysia fields (first implementation in 1998). This paper explains the detailed workflow from candidate selection to execution, challenges, and results from this successful pilot. There were three reservoirs completed in Well 8. The perforation strategy utilized 4 SPF 10/350 degree phasing self-gravitated oriented perforations which was executed under dynamic underbalance conditions to achieve optimal perforation tunnel cleanup. The perforation interval was kept short (< 10 ft) to ensure uniform treatment. One of the key steps in achieving successful resin placement is formation injectivity. Acid was pumped and injectivity tests were conducted before and after pumping to assess the effectiveness of acid treatment. The data acquired from the step rate test was used to determine the Fracture Closure Pressure (FCP) and Fracture Extension Pressure (FEP) where it will define the maximum pumping rate during the sand consolidation treatment. Identification of maximum pumping rate is crucial to ensure optimum displacement of resin into the formation during execution. Pre-acid injectivity results showed poor injectivity in all 3 reservoirs with treating pressures recorded more than the MASTP limit to reach pumping rate of 2 bpm. Near well bore damage removal treatments were executed using mud acid (15% HCl + 1.5% HF) followed by post-injectivity test which showed improvement in treating pressures. By the end of the operation, a total of 68 bbls of treatment fluid was successfully pumped into all three reservoirs. Well tests acquired during unloading and production phase have shown good results exceeding the target rate set during FDP with no sand production observed. It is expected that this new way of sand control for new wells could contribute towards reducing sand production issues in Field A while at the same time provide an incremental gain in oil production. The success of this pilot would open-up more opportunities in PCSB and other operators towards the implementation of similar sand control method for new development wells.
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.
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.
The added value of greater reservoir contacts with horizontal wells will be minimisedby an uneven reservoir sweep along thewellbore as the well may intersect heterogeneous formationswith varying properties. This results in early water and/or gas production in thewell. These challenges can be mitigated by deploying Autonomous Inflow Control Devices (AICDs)that can manage the reservoir fluid influx alongthe wellbore and therefore optimise the performance of well.The design of the well completion with inflow control devices is oneof the important steps in field development planning with a strong influenceon the production profileand thereby the economics. An integrated workflow was followed to deliver successfully the first AICDapplication for PETRONAS-Malaysia in an offshore oil reservoir with huge uncertainties in remaining oilthickness and current fluid contacts. The workflow comprised pre-drilling studies including AICD flow looptesting, well candidate selection, flow performance evaluation (static/dynamic modelling) and post-drillinganalyses including real-time completion design, history matching and comparison ofproduction data with neighbouring wells. In the 2018 infill development campaign, improved productionwas targeted by the installation of AICDs in wells atoffshore Sarawak. AICD completions ensurebalanced contribution from all reservoir sections and limit gas and water production. The chosenhorizontal well was drilled in a very thin formation with the oil rim average thickness of 13ft, the thinnestAICD application to date. The well intersected two geological layers with differentproperties.Alarge gas cap and an aquifer were located above and below the well. The oilproduction from this well was expected to be impaired significantly due to a high probability of early waterand gas breakthrough, potentially within days or weeks. Two analogue wells drilled in 2013 suffer from both issues despite being completed with passive ICDs. Through teamwork between the companiesinvolved in the campaign, the well was successfully completed with an RCP AICD completion. The wellwas segmented in several compartments and a tailored AICD completions was designed to restrict theproduction of unwanted fluids properly. The AICD completion has delivered a 200% increase in oilproduction while it has significantly reduced GOR (up to 90%) and water cut compared to several offset wellswith various other completions.The AICD is an active flow control device that delivers a variable flowrestriction in response to the properties of the fluid and the rate of flow passing through. The lessonslearnt from pre and post-installation studies will be discussed here. The AICD completions enabled theoperator to implement an optimum reservoir drainage strategy that uses downhole control which willbe manipulated autonomously based on well dynamic condition instead of surface control.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn general, mature oilfields have a good portion of the remaining reserves still trapped due to inefficient drainage, production decline, increase in water cut and sand production and aging of the existing systems. This paper addresses techniques and initiatives to optimize development plans in a mature field. For Bokor Field in particular, there have been identified and implemented opportunities such as Infill drilling and workover optimization, dynamic underbalance perforation (DUP), matrix acidizing and propellant stimulation, water shut-off mechanical (WSOM), sand management, through tubing stand alone screens, deployment of electrical submersible pumps (ESP) and gas lift NOVA valves, real time surveillance (DHG, DTS and LiftWatchers*) and optimization, and microbial EOR.Before the implementation of these techniques, this field had a daily oil production equivalent to 10 MSTBD (after fields decline) and the current production is 26 MSTBD. The two main reason for this increase are:• New technologies were employed in this oil field with dramatic results incorporating new hydrocarbon reserves, via 3D seismic techniques, high resolution stratigraphy and better static and dynamic simulation models. • Multidisciplinary integrated studies to increase field ultimate recovery factors by improvements in drilling, workover, stimulations, facilities and EOR methods.
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