Objectives/Scope An Unconsolidated Near Wellbore (NWB) area of the formation as well as the high fines content in the formation have led to massive sand and fines production and therefore, Loss of Pressure Containment (LOPC) at surface facilities. Resin sand consolidation to strengthen the NWB area and fracturing to immobilize fines during production are necessary. However, performing both resin sand consolidation and fracturing completions in multizonal reservoirs is too costly. Therefore, a single trip multizonal sand consolidation and fracturing job is performed to reduce operational days and cost Methods, Procedures, Process Three (3) different techniques to perform resin sand consolidation and fracturing are compared. First, is using a "Mechanical Service Packer (MSP) with Sand Plug" to perform both resin sand consolidation and screenless fracpack jobs. Second, is using "MSP with Sand Plug" to perform resin sand consolidation and to utilize Multizone Single Trip (MZST) tool to fracpack. Third, is using a Straddle Packer to perform resin sand consolidation and to utilize MZST tool to fracpack. The first technique was performed in wells W-1 and D-1 and the third technique was performed in well H-1 Results, Observations, Conclusions The technique to perform resin sand consolidation as part of the primary sand control method in a new well followed by fracturing the formation to immobilize the fines is a novel technique. The utilization of a Straddle Packer to perform multizonal single trip resin sand consolidation followed by running MZST tool for fracturing has managed to reduce the operational days by more than half compared to the other techniques. Sand and fines production has been reduced significantly in wells W-1 and H-1 as a result of the novel technique. Novel/Additive Information The decision to perform resin sand consolidation prior to fracturing the reservoir is dependent on the Ultimate Compressive Strength (UCS) of the rock. Unconsolidated formation with UCS less than 2,000 psi is to be strengthened via resin consolidation. The single trip multizonal resin sand consolidation via straddle packer was first performed in well H-1 with 6 zones.
Many oil and gas fields have long been suffering from sand production due to either the absence or failure of primary well sand control. To avoid mobilizing costly work-over rig to pull out the tubing, operators have tried various thru-tubing remedial sand control. The well's condition such as sands accumulation and space constraints due to small inner diameter of tubing always make this remedial job challenging. It is not surprising that the results are not all satisfactory. Among the industry-recognized remedial sand control, Stand Alone Screen (SAS) is the simplest and the cheapest method. Many SAS have been installed but most were failed with screen erosion as the main failure mechanism. Flowing high velocity fluid with sands wears out the screen fast making it impossible for the sands to bridge and to create formation sand pack around the screen. Ceramic Sand Screen (CSS) technology which was recently introduced to the industry aims to address this erosion issue. Having more than ten times hardness of stainless steel, sintered silicon carbide ceramic material in CSS offers superior resistance to wear. The pilot was conducted by installing CSS in three (3) selected wells with sand production history. While waiting for acoustic sand monitoring installation, the wells were put on production with the same choke size and regular manual samplings were conducted to monitor the sand production. The acoustic sand monitoring campaign began in November 2017. Sands production was carefully monitored during the process to determine the final choke size at which the wells would continuously produce. In the middle of the campaign due to adverse weather conditions, all non-essential personnel had to be abruptly demobilised from the field leaving acoustic sensors hooked-up to the respective flow line. This gave opportunity to have unplanned extended sand monitoring window. Loss of Primary Containment (LOPCs) occurred in two CSS wells not long after that. In one the choke body was heavily eroded and the other well had a punched hole at the first elbow of the flowline. These incidents prompted full investigation to be conducted. This included pulling out the installed CSS and performed tear down analysis. Acoustic sand monitoring that just happened to be available in one of the wells proved to be critical in understanding the CSS failure. The paper presents briefly on the CSS pilot project, the chronology of events until the incident, sands production trend from the acoustic sand monitoring. Using all available information, the paper provides details analysis on CSS failure mechanism.
Most Malaysian oil production is heavily reliant on gas lift. Aging assets experience declining lifting efficiencies due to depleting reservoir pressure and increase in water cut. This impact PETRONAS' capability to deliver national hydrocarbon production targets. New developments and further improvements to gas lift facilities are likely to erode the economic value of assets without even considering the potential time impact due to the complexity in delivering gas compression upgrades or gas import projects. PETRONAS' primary goal within Malaysia is to sustain production and maximize the remaining recoverable reserves. To realize this target it is widely acknowledged that the company must think differently. Alternatives to gas lift have been considered for rejuvenation of brownfield assets and development of marginal assets using a ‘fit for purpose' approach resulting in some relatively low Capital Expenditure (CAPEX)/Operating Expenditure (OPEX) solutions. One such method identified was Through Tubing Electrical Submersible Pumps - Cable Deployed (TTESP-CD). TTESP-CD technology is a game changer that can challenge the boundaries of traditional engineering with a truly rig-less deployment of an ESP system with full compliance to API/ISO requirements and demonstrating up to 70% cost savings over conventional offshore ESP installation methods. The TTESP-CD innovation helps in improving the asset value through gas prioritization, gas lift reallocation, flaring reduction and increase in lifting efficiency. TTESP-CD is also in line with the company digitalization concept due to the baseline data available from surface and downhole equipment. This technology has been declared a success through pilot deployment in an offshore field within the Sarawak Basin with an incremental gain of 250BOPD, 0.3MMSTB in reserves acceleration and 22 months run life as of Feb 2019. This has been a key step for building confidence in the wider application of the technology. Lessons learnt and best practices from the pilot implementation have been applied to ongoing and future projects and serve as a good foundation for further development of the technology. To date, approximately 20 candidates for the TTESP-CD application have been identified for replication in Malaysia within the next 2 years across 3 regions. There are various challenges faced when implementing this technology on aging offshore assets that was never designed for ESPs which include; space availability for deployment equipment and surface electrical equipment, power availability and distribution, instrumentation, data transmission, structural integrity and operational mind set. PETRONAS sees a bright future for TTESP-CD application and technology which includes layer to layer matrix dump flood, interim production and well unloading/DST well unloading.
There are five wells planned to be drilled in B field infill campaign starting Q3 2020 - Q1 2021 as per development plan. Two wells are planned to be installed with Digital Intelligent Artificial Lift (DIAL) system, which one in single string completion and another one in dual string completion. This paper will mainly describe on the DIAL application in dual strings completion in B field. The DIAL system has circumferential 3 active orifice valves to open/ close selectively or in combination, which is communicated and operated through TEC cable from surface remotely. Given that this will be the second DIAL system installation in the world, a back up gas lift mandrel (GLM) will be installed to mitigate the risk in case the DIAL system fails to work due to any unprecedented reason so that conventional gas lift valve can be installed in GLM and gas lift operations can be commensed. The world's first DIAL installation in dual strings was completed in a different field offshore Malaysia in Q2 2020. During well completion and system installation, all the DIAL units in short string were functioning well, however there were some issues initially observed in Continuity Resistance (CR) inconsistent reading during run in hole completion and then total failure was observed in long string after its installation based on CR test, TDR (Time Domain Refractometer) test, and Scope Test due to unprecedented technical issue which affected the downhole cable to receive and send electrical signal to operate DIAL valves. The risk assessment has been conducted with associated parties based on the failure analysis and lessons learnt from the first DIAL application in dual strings in order to implement mitigation plan and proceed with DIAL application in B field. This step is very crucial to build the learning curves as well as improve the operator's understanding on for future DIAL application in dual strings. This paper will summarize the DIAL tool functionality and its design, failure analysis & lessons learnt from other field offshore Malaysia, and risk assessment & mitigation plan carried out for the DIAL application in dual strings in B field. It marks the second application in the world at present & first successful DIAL application in dual strings worldwide presently.
Following the first pilot success of the truly rigless 3-1/2" tubing cable deployed ESP (TTESP-CD in offshore field of Sarawak Basin, PETRONAS has taken steps to further advance in the technology development and application through more replications within Sarawak and Malay Basin. PETRONAS had been looking into a strong business case for the TTESP-CD technology for a wider application throughout Malaysia region by looking at fields with strong/moderate water drive and low bubble point pressure besides having other limitations on the platform including the facilities reliability issues. TTESP-CD are to be applied widely in Malaysia with more flexibilities in design and improvement towards the subsurface equipment, installation equipment and procedures. With the challenges in the existing completion and production requirement for replications, based on the lesson learnt from the pilot implementation, multiple improvements to the system have been done including; 1) A High Rate Slim Pump with Flexible Application 2) Alignment Tool for Cable Hanger Orientation. With this in place, more opportunities identified for the candidate selection which improve the installation philosophy specifically in dual string applications and enhance the efficiency in installation procedures. Case studies of TTESP-CD replications in Malay & Sarawak Basin for Field T, Field B and Field P presenting the best case for TTESP-CD application with improvement to design, equipment and application. These will bring additional value to PETRONAS with estimated production gain of ∼1.5 KBD and up to 1.2 MMSTB reserves to be monetized with additional value saving of up to RM 6 Mill. Besides the subsurface challenges, aging offshore assets brings a lot of challenges, especially on the space availability, structural integrity, power availability and distribution, instrumentation and data transmission. This requires an integrated approach from multiple disciplines in delivering the studies as per required within the targeted timeframe.
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