Field A consists of multi stacked reservoirs in high geological complexity and heterogeneity setting, with waterflooding has been the secondary drive mechanism for the past two decades. However, in recent years, the field experiencing significant production decline that warrant immediate mitigation plan and action. Therefore, this paper highlights challenges and best practices in rejuvenating water injected reservoir to improve field production by integrating geological re-interpretation, data acquisition and analytical evaluation. The reservoir is defined in deltaic environment with complex fluvial reservoir architecture. Despite no indication of structural trap or compartmentalization, there is significant variation in reservoir performance across the field indicates lateral heterogeneity that is affecting the areal sweep efficiency. Poor production-injection allocation data due to commingled production, aggravated by tubing leaks have hindered for an optimum formulation of waterflood strategy in the past. As part of the mitigation plan, depo-facies definition and stratigraphy boundaries were further refined, guided by well and reservoir pressure performance. Besides, inter-well tracer injection implementation proved to be the game changer - unfolded hydrodynamic connectivity and flow path of injected water understanding, established actual producer and injector pairing, and identified poor or unswept areas. It was supported by comprehensive analytical water injection performance analysis including Hall's Plot, Chan's Plot, Jordan's Plot as part of the routine surveillance activities to trigger any non-conformance. More aggressive well intervention also helped to identify and rectify well issues. As the outcomes, there is opportunity to increase water injection rate by 30% field wide by reactivating idle wells, converting producers to injector, and maximizing the existing injection within the safe fracture limit. The subsurface risks on fracture gradient uncertainty and sweep inefficiency due to water cycling to be mitigated via injectivity test with gradual injection, close monitoring of liquid rate handling at surface, and pattern balancing between injectors and producers. The liquid rate is expected to be restored and sustained nearing the historical peak, hence improve field production and temper the decline. This paper presents the best practices to address the challenges in a matured waterflood reservoirs, considering the complex geology setting. Understanding of the flood pattern from tracer analysis, supplemented by producer-injection performance assessment and well integrity status validation enabled water injection to be ramped up at the right area in strategically and safely manner.

Sand production is one of the most common issues in the oil and gas industry which impacted the production and equipment. Thus, downhole sand control is introduced to provide the mechanism for wells to produce with minimal sand production to surface and reduce the lifecycle OPEX of the well. Nevertheless, different sand control methods may influence the well production performance differently. This paper demonstrates a comparative manner towards understanding of the effect of various sand control techniques on well productivity completed in a mature field. The methodology involves the use of statistical comparison of the actual production performance of three (3) main sand control methods installed over 20 years of production period in Field D. The approach includes in-depth assessment of the well production performance in relation to the recorded sand count and the intervention frequency ratio. It is observed that the wells completed with OHSAS displayed remarkable production performance but high in sand production as compared to other sand control techniques. However, wells completed with CHSAS showed satisfactory production performance with good sand control. In fact, the CHSAS wells are still active and producing even after 8 years of completion without any integrity issue. For more advanced option i.e. CHGP, the wells showed comparable results with CHSAS both in term of performance and sand count. Depending on the proppant placing techniques, wells completed with HRWP have the best production performance, followed by Extension Pack then Circulating Pack. It indicates that more rigorous sand control design will effectively retain the sand downhole but reduce the well productivity as well. Therefore, the key is to find the balance between these two variables in determining the optimum sand control option especially when different sand control methods require different level of investment with certain expectation in return. The evaluation approach described in this study offers an easy guide and benefit the practicing engineers to select the optimum sand control in addition to theoretical studies that based on geo-mechanics analyses, PSD, SRT etc.

Waterflooding for pressure maintenance often seems straightforward with key objective being voidage replacement as demonstrated through material balance. Even though pressure maintenance can be achieved, it may not directly translate into higher production if efficient sweep is not attained, and oil has been bypassed. This paper demonstrates a real case study at Field S on how swift and integrated mitigation plan successfully addressed the production impairment during the initial water injection period. Field S started injection through newly drilled peripheral water injectors to fill up the voidage created by earlier production volumes hence tempered the pressure decline. Reservoir response was observed from downhole pressure gauges as early as after the first few days of injection in several producers. The first water breakthrough was then identified few months after at the most up-dip wells and resulted in producers died off. At the expense of voidage replacement ratio (VRR) performance, intermittent flow strategy was deployed as temporary measure, to revive and keep the producers flowing, while flow diverter chemicals have been under evaluation to serve as a more sustainable solution. Impacted producers were determined to have good connectivity with the injectors as shown by streamline analysis, diagnostic plot, salinity measurement and log correlation. This is easily validated with pressure response recorded via PDG (pressure downhole gauge) throughout injection period. It was observed that high permeability contrast ratio presence across multiple sand lobes at the affected producers with the highest permeability was recorded up to Darcy range. While such contrast was absent at injectors, this specific sand lobe still effectively provides the preferential flow path between injectors to producers and lead to channeling effect. Managing drawdown through choke optimization was ineffective as the short distance between injectors and producers allows rapid water charging through the high permeability streak. However, shutting-in injection temporarily managed to slow down water production almost promptly. Subsequently, intermittent injection strategy implementation enabled certain amount of solution gas being liberated to provide in-situ gas lift effect inside the tubing for continuous production. The producers were successfully put back on production within weeks with close monitoring and surveillance. Next step, flow diverter chemical will be injected to partially block the channeling path, hence maximizing the well potential and oil recovery. Production upset caused by early water breakthrough is a common issue in waterflood reservoir. However, by understanding the root cause, supported by prudent surveillance practices and operation flexibility, the production downtime can be minimized as showcased in this paper. Besides, geological and petrophysical input are pivotal in understanding reservoir or well performance issues.

Marginal field development commonly face setback when it comes to an investment decision, which makes it technically and commercially very challenging to be developed. Technologies that usually applied in big fields may not be economically relevant to the marginal fields, despite require the same assurance and functionality. Well completion cost itself can take up to 50% of the total well cost, especially for fields that potentially must deal with sand production, high CO2 and/or H2S content, artificial lift, and multilayer zonal completion and isolation. This paper demonstrates an integrated approach to identify and define the optimum well completion strategy for such conditions in a Malaysian oilfield. The first step is to list all the operational issues and challenges of producing from the neighboring fault block and other analogue fields experience. Leveraging on the available data and types of completion that have been installed, a set of scoring is given to different completion type, considering the sand production control effectiveness, good well performance, and long well life span. The shortlisted completion types were further evaluated based on the following criteria: Production flexibility Early monetization Operation complexity (drilling and completion) Sand production management Sand control failure probability Associated Risks Stand-alone economic As a result, eight (8) completion strategies were investigated namely Monobore, Monobore wih resin, Cased & Perf, Cased & Perf with resin, Open Hole Stand Alone Screen (OHSAS), Cased-Hole Stand Alone Screen (CHSAS), Cased-Hole Gravel Pack (CHGP); using circulating method or frac pack. Different completion has its own advantages and disadvantages. Structured scoring system was again applied to guide the decision-making process. The key elements in the decision thought process are the associated cost of each option, the skin factor that affect the production and reserve estimation, and ultimately the Net Present Value (NPV) indicator. In conclusion, identifying the optimum well completion will never give a single solution answer. However, the most important thing is to consider all the decisive factors and properly evaluate all options. In our own real example, the option that gives the best NPV coupled with tolerable risk (HSE risk i.e. less issue at surface) was selected as the optimum well completion strategy to be used in the development plan.

It is widely known that for highly corrosive environment, corrosion-resistance alloy (CRA) is recommended as the production tubing material. This is because its alternative, carbon steel (CS) is prone to corrosion that leads to integrity issues such as tubing leak and tubing parted. However, CRA usage would increase well cost resulting in unattractive commercial implication especially for a marginal field development which tends to be very sensitive economically. This paper gathers the actual performance of various tubing materials that have been installed in a high CO2 oil field in Peninsular Malaysia, in which the findings would be used to determine a proper tubing material selection strategy for future development. Actual data from 30 years of production was collected and to be analyzed statistically. Each well's water cut trend was evaluated to establish relationship between producing water to the corrosion rate and metal loss in the presence of CO2. It is noted that some wells completed with CS both in single and dual completion are still producing with no leaks after 30 years. This case applies to either single string or dual string, with both strings are completed as producer. However, majority of active CS-completed wells require tubing pack off to overcome multiple leaks, especially in dual utility wells. Notably, wells that are completed with CRA e.g., 13 Cr are active with no possible leaks at all. Some wells which are completed with glass-reinforced epoxy (GRE) and higher grade of CRA; 22 & 25 Cr, also do not show any potential leaks or tubing integrity issue. It is proven and highly recommended to complete high CO2 fields with CRA material. Nevertheless, by understanding the well and reservoir performance, particularly on the effect of water cut in relation to general corrosion due to CO2, the use of more expensive materials can be optimized. This paper is to discuss, in the context of marginal field development where production life is relatively shorter and production rate is low, the consideration of deploying a cheaper material and/or less corrosion-resistant substances as the tubing material to make the development more commercially attractive or remain status quo with CRA.