Controlling sand has been one of the most difficult challenges in oil production in Upstream Malaysia operations. Conventionally, Cased Hole Gravel Packs (CHGP) or Open Hole Gravel Packs (OHGP) are installed to prevent sand from being produced with the oil to the surface facilities. However, both methods require massive operations and high cost which impact the overall economics of the project. This paper summarizes the technology evaluation of Shape Memory Polymer (SMP). This includes the working philosophies, candidate selection, risk identification and mitigation plan, and success criteria developed for this technology. Common gravel packing technique is accomplished by packing gravel in the annulus between the screen and formation sand face, where the gravel acts as a barrier preventing the migration of the formation sand. The new technology does exactly the same task by expanding SMP which conforms to the sand face. The only difference, in gravel packing, the contact medium with the sand face is the gravel whereas in this technology the contact medium is the SMP. The operational sequence is very similar to the installation of Open Hole Stand Alone Screens (OHSAS). From the evaluation, one well was identified by the team at BS field for piloting this technology. The well will be part of a development campaign executed in Q2 2020. Details of the well design and scope will be shared briefly, as well as a commercial comparison between conventional sand control methods and SMP. The pilot test at BS field will be discussed including technology evaluation, candidate selection, well completion design, risk mitigation and others. Several case histories and current available field implementation are also taken into consideration to properly plan the pilot test. The success criteria outlined would help to oversee the performance and continuous monitoring of the system before it can be declared a success. Potential candidates for replication of this technology have also been identified within the Operator's company in the near future. The possible pilot test for this technology is the result of strong and good collaboration between the Operator and Service Company. If it is a proven success, this technology will become a game changer for downhole sand control in the petroleum industry which will be able to maximize production and save operational expenditures, while ensuring the highest reliability.

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.

Losses are common in carbonate reservoir drilling due to highly fractured nature of limestone and the existence of karst. Complete and unsustainable fluid losses encountered in the offset well threatened the loss of the primary barrier -hydrostatic column -that could result in a catastrophic well control incident / loss gain scenario. Total losses in the offset well were approximately 25,000 bbls. Losses were stopped only with cement plugs. A total of 17 days were spent to mitigate the losses. The well was plugged and abandoned.To drill and develop this marginal carbonate field with efficient and low cost wells, the team decided to use Mud Cap Drilling (MCD) with Continuous Annular Injection. The sub-normal nature of the reservoir allowed the use of this technique as opposed to a more conventional Pressurized Mud Cap Drilling (PMCD) method utilizing Light Annular Mud (LAM). Continuously injecting seawater down the annulus to prevent gas migration while simultaneously injecting seawater down the string to transport cuttings up to the loss zone and cool the bit, eliminated the mud cost and fluid logistics that normally dominate the PMCD process.During the development program, two horizontal wells penetrated the carbonate at the same TVD and only one of the wells experienced complete and unsustainable losses. Carbonate structures are anisotropic. Several wells can be drilled that do not experience losses yet the next well in the same field could require MCD. For this reason it is necessary to prepare for MCD as a contingency when drilling carbonates. No kicks or well control issues were experienced during this development program. Well barrier policies were accomplished by maintaining the annulus with overbalanced fluid (seawater) at all times using this method. Well was drilled to TD and completed successfully, and all the primary well objectives were achieved. Drilling time was reduced significantly by over 50%, and fluid cost for this operation was reduced to almost zero. This innovative technique was applied for the first time in PCSB Malaysia drilling operations.

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.

As part of well cost reduction initiative, screenless fracpack has been successfully applied in Field D in which gravelpack or fracpack have been the prevalent sand control completion methods. This paper discusses the first application of screenless fracpack in Malaysia with description on design process, implementation method, challenges in design and execution, production performance, and the recommended way forward. Typical gravel pack or fracpack would require installation of downhole screen and packer assemblies, followed by gravel pack or fracpack pumping. The associated cost ranges from USD 1 million to USD 2 million for a multi-zone well. However, screenless fracpack application eliminates the high-cost screen and packer assemblies. Perforations are made with vertically oriented 0-180 degree phasing (up and down) to maximize fracture alignment with perforations as well as to minimize potential sand production from the perforations without fracture. Subsequently, perforations and near wellbore matrix are treated with resin injection to consolidate near wellbore formation in ensuring good sand/fines control in formation that is not fractured. Hydraulic fracturing utilizes tip screen out method to create short fracture length and wide fracture width to maximize dimensionless fracture conductivity. Proppant can be resin coated or treated with network of fibers to control proppant flowback in absence of downhole screen assemblies. All planned procedures have been successfully conducted. Perforations were made in a short interval i.e. about 2m in length with limited entry 4 SPF/ 0-180 degree phasing. Dynamic underbalance technique was incorporated to maximize open perforations effectively. Resin injection plan was dropped due to low permeability and low injectivity. Resin squeeze into a tight formation can end with either incomplete resin and overflush injection, or fracturing with the viscous resin, either of which would damage the formation. A highly conductive fracture has been created with tip screen out. Nolte Smith log-log plot showed a unit slope, an indication of tip screen out. Proppant flowback control was obtained with resin coated proppant. Post screenless fracturing, the well was carefully unloaded and cleaned. Well production showed good productivity and effective sand control. Currently, other fields are being studied and considered for the same application. Screenless fracpack is applied for the first time in a field offshore Malaysia. It is a bold step change whereby gravelpack or fracpack are commonly used as sand control. The application was driven by well cost reduction effort and the application is currently considered for replication in other fields. The benefit of the new method is not only the well cost savings by elimination of screen and packer assemblies, but it also provides full bore access and simpler well interventions. This application helps in brownfield and marginal field development whereby small reserves may negatively project economics due to high cost for gravelpack or fracpack installation.