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.

Field A is a mature hydrocarbon-producing field located in eastern Malaysia that began producing in 1968. Comprised of multistacked reservoirs at heights ranging from 4,000 to 8,000 ft, they are predominantly unconsolidated, requiring sand exclusion from the start. Most wells in this field were completed using internal gravel packing (IGP) of the main reservoir, and particularly in shallower reservoirs. With these shallower reservoirs continuously targeted as good potential candidates, identifying a sustainable sand control solution is essential. Conventional sand control methods, namely IGP, are normally a primary choice for completion; however, this method can be costly, which requires justification during challenging economic times. To combat these challenges, a sand consolidation system using resin was selected as a primary completion method, opposed to a conventional IGP system. Chemical sand consolidation treatments provide in situ sand influx control by treating the incompetent formation around the wellbore itself. The initial plan was to perform sand consolidation followed by a screenless fracturing treatment; however, upon drilling the targeted zone and observing its proximity to a water zone, fracturing was stopped. With three of eight zones in this well requiring sand control, a pinpoint solution was delivered in stages by means of a pump through with a packer system [retrievable test treat squeeze (RTTS)] at the highest possible accuracy, thus ensuring treatment placement efficiency. The zones were also distanced from one another, requiring zonal isolation (i.e., mechanical isolation, such as bridge plugs, was not an option) as treatments were deployed. While there was a major challenge in terms of mobilization planning to complete this well during the peak of a movement control order (MCO) in Malaysia, optimal operations lead to a long-term sand control solution. Well unloading and test results upon well completion provided excellent results, highlighting good production rates with zero sand production. The groundwork processes of candidate identification down to the execution of sand consolidation and temporary isolation between zones are discussed. Technology is compared in terms of resin fluid system types. Laboratory testing on the core samples illustrates how the chemical consolidation process physically manifests. This is used to substantiate the field designs, execution plan, initial results, follow-up, lessons learned, and best practices used to maximize the life of a sand-free producer well. This success story illustrates potential opportunity in using sand consolidation as a primary method in the future.