The CO2 sequestration project is becoming increasingly attractive due to tax exemption benefits and as an initiative to reduce the global warming effect (D'Alesio, P., Poloni, R., Valente, P., & Magarini, P. A.2010). One of the major challenges in CO2 sequestration project is to ensure that the injection well integrity is intact throughout the well operating life. CO2 gas leakage to the surface or sea is unacceptable. Therefore, the considerations of using exotic/premium tubing materials are usually considered as the base case for continuous long-term operations (Baklid, A., Korbol, R., & Owren, G.1996). Typical materials used for CO2 injector wells are either Corrosion Resistant Alloy (CRA) or epoxy lined tubulars. The most widely adopted CRA material is 25 Cr (L. Smith, M.A. Billingham, C.-H. Lee, D. Milanovic, 2011). Selection of 25 Cr material is considered as conservative and may well be overdesigning. The main drawback is the high well cost associated with the application of 25 Cr tubing. Meanwhile, alternative materials such as epoxy lined tubulars are exposed to high temperature and pressure blistering effects and prone to mechanical damage caused by wireline activities, hauling, running, and pulling off the tubing (Newton, L. E., & McClay, R. A, 1977). Application of materials other than 25 Cr for CO2 injector wells, such as 22 Cr, Super 17 Cr, Super 15 Cr, Super 13 Cr, 13 Cr and carbon steel are uncommon but may be fit for purpose. Detailed studies using analytical method and physical tests are required to further qualify these materials for application in CO2 injector wells. These studies should cover all possible conditions throughout the well life such as injection, shut-in, flowback and by considering surface and bottom hole conditions which may contribute to increase in the corrosion rates for different types of materials. Other tests warranted before selecting the suitable material for field application include physical coupon, Sulfide Stress Cracking (SSC) and Stress Corrosion Cracking (SCC) tests. This paper describes the material selection methodology and corrosion studies performed in the K1 field CO2 sequestration project using the other materials mentioned above as an effort to optimize well costs and improve overall project economics without jeopardizing the CO2 injector well integrity.

Sand control application in gas wells is very challenging, especially in the application of a standalone sand screen (SAS) due to the high erosional risks. Many failures have been observed in the industry over the years causing production deferments and additional OPEX to the operators for remedial sand control operations. This work presents the performance evaluation of a unique SAS in open hole completion concept piloted in a horizontal gas well and the replication in other new wells in a Malaysian gas field. In 2012, a pilot gas well was completed with SAS with optimally placed flow segmentizers along the horizontal completion to limit the screen erosional risks. The placement was determined using a tool developed through an R&D. It estimates the optimum locations of the flow segmentizers based on the targeted SAS life or erosional velocity limit imposed. At the heart of it is a proprietary erosion model specifically developed for SAS application. The well performance was compared to adjacent wells producing from the same reservoir but completed using the conventional open-hole gravel pack. The pilot well achieved higher Productivity Index in comparison to the adjacent wells. Over the 10-year observation period, the production performance was consistent with minimal skin values and no sand production issues. Multifinger Imaging Tool (MIT) was run to measure the erosion levels in the tubing and the result indicated very minimal erosion because of sand production even after several years of production. Recently, another one (1) new infill well was drilled and completed with the same concept as the pilot well. The segmentizer placements were supported by an optimization study based on the expected production scenario. Positive flow back results with no indication of sand production was detected from the intrusive sand monitoring equipment. With the application of SAS and flow segmentizers, a cost reduction of 25% as compared to more complex application of open-hole gravel pack was realized.

The Temana field consists of unconsolidated reservoirs which require active sand control. Conventional Internal Gravel Packed (IGP) technique has been widely applied as it has provided a reliable means of abating sand production. These completions however, have shown high skins (>15) which had increase with time due to fines migration into the packed area especially with the advent of water production. In many cases, flow efficiencies were reduced by 70% and this had severely affected well performances with aging. Stand Alone Screens (SAS) and Expandable Sand Screens (ESS) had also been applied in some fields with mixed success especially for high angle or horizontal wells. Experience gathered from these previous sand control measures coupled with the emergence of improved design and production of SAS has enabled a shift in our sand control philosophy. Critical Drawdown Sanding Pressure (CDP) consideration plays an important role in the new sand control strategy we recently applied. To ensure that the CDP does not exceed during well production, we focus our attention to maximize well productivity by implementing open hole completion at high angle of trajectories (70 deg or even horizontal). Furthermore, the reservoir sections were drilled with non damaging drill-in fluid treated with enzyme breaker and screens were run in conditioned, solids free mud to minimise plugging. Proper sizing of the screen slot size is critical to ensure that screens are not plugged as commonly experienced in SAS applications. Annular flow were minimised by running constrictors suitably placed with the screen assembly. Finally, strict enforcement of slow bean-up policy during the initial production of the new wells has maintained the screen's integrity in the wells completed so far. This paper describes our new sand control application and the excellent production performances achieved from the new wells in the recent drilling campaign in Temana. Introduction Temana field was discovered in 1962 and brought into production in 1979. The field is located approximately 30 km West of Bintulu in a water depth of approximately 96 ft. It consists of three hydrocarbon accumulations, namely Temana West, Temana Central and Temana East (Fig. 1). The field has undergone a complex tectonic history and is highly faulted and compartmentalized. The latest development is from the existing structure Platform A, which penetrates the Temana Saddle, which is located in the southeastern part of Temana Central. The main reservoir target is the I-65 sand. The sand has a fining upwards log signature with a sharp base at the bottom of the sand. The sand contains light oil of about 41.1 deg API with reservoir pressure of 1,553 psi, average porosity of 26% (oil) and effective permeability of more than 1 Darcy. The main drive mechanism of this reservoir is depletion drive with weak to moderate aquifer support. There are 7 existing platforms (Fig. 2) with two additional production processing facilities platforms. About 44 wells out of 74 wells of the existing oil producer wells were completed with cased hole gravel packed (IGP) and only 2 wells were installed with premium screens in horizontal open holes. Based on the well test data for these wells for a similar type of reservoir, the average skin is 10–15 even after immediate production and increase up to 20–30 after longer years of production. The average PIs of these wells typically ranged between 1–20 stb/d/psi. Investigation shows that the eminent cause of increasing skin or pack impairment and deterioration in the production wells is due to fines movements packing into the gravel-packed sand and this was aggravated when water breaks through.

Objectives, Scope This paper provides valuable insights on aqueous retarded acid system evaluation based on laboratory testing, literature review and engineering analysis prior to the field application for a candidate well in a gas field, offshore East Malaysia (Figure 1). The field is a reefal carbonates build-up overlayed by a thick shale sequence and is one of the deepest fields in Sarawak Asset, in which the produced fluid contains up to 3,500ppm H2S, 20% CO2 and bottomhole temperature up to 288°F. Production enhancement for this carbonate reservoir requires application of a more effective approach to address challenges associated with acid placement and reservoir contact in long pay zones of complex diagenetic facies high temperature carbonate reservoirs, thereby improving return on investment. Figure 1Structural map of Central Luconia carbonate platform offshore Sarawak, Malaysia (Janjuhah et al. 2016) Methods, Procedures, Process The workflow adopted for the stimulation job involves thorough historical production data analysis, detail petrophysical review to evaluate reservoir properties, in-depth production performance analysis (i.e. nodal and network modeling), completion review to ascertain damage mechanism and economic evaluation that include decision risk analysis to evaluate all range of probabilistic outcome. Initial selection of stimulation fluids was based on the mineralogical composition of the main producing formation. A detailed study of reservoir rock and its reaction to various acid systems has been based upon software modeling where sensitivity analyses involving multiple treatment schedule scenarios incorporating various acid and diverter fluid systems are considered. Coreflood experiment was then performed to determine the Pore Volume to Breakthrough (PVBT) comparing emulsified acid with aqueous retarded acid at temperature of 250°F, injection rate of 3ml/min and at confining pressure of 1,500psi. The low PVBT values (i.e. 1.125 and 0.521) and unique breakthrough features obtained from the coreflood confirmed that aqueous retarded acid is effective to stimulate the carbonate reservoir. Compatibility testing was also conducted to assess the stability of the retarded acid recipes and potential reaction with reservoir fluids (i.e. water and condensate), downhole completion and surface equipment. Results, Observation, Conclusion An established stimulation software was used to refine the acid volume calculation and placement analysis. Field trial was made using combined application of the aqueous retarded acid and viscoelastic diverting acid. Considering several case scenarios, the remedial treatment was performed via bullheading to achieve optimum injection rate within 5bpm to 7bpm. Total of 197bbls acid and 197bbls diverter was be pumped during the treatment that will be split in several stages to achieve average invasion profile of 2.8ft and -1.3 skin value. This paper presents aqueous retarded acid system as alternative to widely used emulsified acid systems. Field application of the approach supports the theoretical findings based on substantial improvement in well production, pressure matching of the remedial treatment and calibrated nodal analysis assessment. This demonstrates the value of holistic approach of laboratory testing, comprehensive software modeling and application of enhanced stimulation fluids to overcome complex technical challenges Novel, Additive Information The field production was previously constrained by its high CO2 levels and the supply gas ratio agreement. The information and lessons learnt from this paper will be applicable as evident of practical improvements to achieve sustainable production from the field since it has a strategic importance as production, processing and export hub to other four gas fields. Recent CO2 blending project has allow a better distribution of gas across the network and therefore demand higher production from the field, thus further unlock it potential to achieve economic optimization.

One of the key successes in optimising a mature offshore oil producing field with water drive mechanism is to actively unlock additional oil production from reservoirs that have not experienced water breakthrough while maintaining gross production from reservoirs that have started producing water. This can be achieved by drilling more infill wells to create additional oil drainage points; however this is a very capital intensive investment. The other approach is to perform stimulation jobs on existing wells (both idle and producing) as part of production enhancement activities to increase well productivities which are comparatively more cost effective. With the increase in well productivities, these wells can be produced at lower drawdown which can delay water breakthrough. This paper describes a holistic approach from understanding well inflow productivity problem due to severe downhole asphaltene or wax deposition issues, formulating the right organic-solvent-mud-acid chemical recipe for the well stimulation jobs, selecting the appropriate well candidates, and optimizing offshore stimulation job execution to ensure good chance of success. The stimulation campaign for 3 wells was carried out between Dec 2009 and Jan 2010 and was proven to be very successful. The cost per job was reduced by 30% compared to previous stimulation job, oil production for all wells increased (including a well which is closed in for 10 years), and up to date, water production has not been observed. Finally, a post job detailed technical analysis was conducted to allow a better understanding on the chemical recipe performances for optimization of future stimulation jobs.