Matrix acidizing is one of the most common well stimulation methods in Malaysian brown fields. Formation damage caused by fines migration has been reported to be among the main reason for productivity decline. The need to conduct acid stimulation arises when the initial rates of the wells are below expectation or when the productivity of the reservoir drops significantly. Various mud acid formulations have been used to treat the wells from the past until recent years. However, some well treatments resulted in low success rate especially for reservoirs with vast variation and complex formation mineralogy. This highlights the need for modified acid recipe from the conventional mud acid system. Mud acid systems are often highly corrosive, resulted in unwanted secondary precipitation and require multiple additives during the treatment. This paper highlights the evaluation and comparison of the novel Modified HF acid against conventional mud acid system through core flooding tests. Multiple cores with various mineralogy were tested. The laboratory test showed that the Modified HF acid system able to generate better permeability improvement compared to mud acid systems. The modified acid recipe gradually sequestrates the major iron minerals throughout the injection to avoid unwanted secondary or tertiary precipitation that could damage the formation. Subsequently, the chemical was successfully piloted in two fields and replicated in other fields across Malaysia. The field applications proved that the novel Modified HF acid system generated outstanding results in production gain and improved the total economics of the project. The novel acid recipe can be an alternative solution when simpler acid systems are favored with lower treatment cost. This chemical is also beneficial for wells that located in small platforms or jackets where minimal amount footprint is available during job execution.

Barium Sulfate (Barite, BaSO4) scale is the most difficult scale to remove due to its low inherent water solubility. After more than 10 years of production in Field A, barite scales are recently found deposited in the tubing and at the topside in one of the oil producer wells. In this case, barite scales are precipitated through mixing of formation water containing high concentration of barium ions and injection seawater with high sulphate concentrations. Successful method of removing barite scales is using chelant based chemicals i.e. EDTA/DTPA. The best possible way to reduce failure risks of the pilot removal application using these chemicals for Field A is through series of lab testing. This paper describes the selection of barite scales dissolver chemicals through establishment of standard laboratory screening protocols prior to field applications in PETRONAS. In the industry, there are various experimental methods to study the effect of barite dissolver chemicals on barite scales dissolution. Since PETRONAS has just recently encountered barite scales deposition issues, it is crucial to have a standardized protocol to ensure the effectiveness of the chosen chemicals to remediate the issue immediately. The protocol developed was based on various references and citations from other operators and chemical service provider. The protocols are divided into three (3) sections in series i.e. characterization of deposit samples mineralogy, barite dissolution and chemical compatibility testing. Prior to barite dissolution tests, deposit samples collected from the wells/topsides are characterized through XRD/XRF analysis, organic scale identification/analysis and acid solubility test. Finally, the most effective barite dissolver chemical will undergo chemical compatibility tests with production fluids, incumbent production chemicals and core samples. Barite scales deposits collected from Field A were found to be radioactive. Testing procedures were in-line with precautions taken to prevent risks exposure to these materials. Scale characterizations indicated samples are dominated by barium sulfate containing some small percentage of calcium carbonate scales and organic contents. Static disintegration and dynamic dissolution tests carried out shows significant results differences where application of barite dissolver chemicals in the well may require coil tubing assistance. Compatibility studies of the dissolver chemical with incumbent production chemicals shows suitability of the different chemicals when the well is flow back after treatment.

Oil production from the field begin with the first oil in January 2003. Unfortunately, the wells produced viscous emulsion which caused the production decline rapidly. Further analysis of the production data showed that the decline in production over a long period of time is very consistent with organic deposition at or near the perforation interval. Over the years, several analyses and production enhancement efforts including chemical and mechanical treatments have been attempted with minimal success. The damaging mechanism was determined to be caused by rare High Molecular Weight Organic Deposit (HMWOD) that have caused a significant pressure drop in the tubing, which consequently restrict oil production and tested to only disperse at above 90°C. It was suspected that the deposit was a naturally-occurring component of the crude oil itself, separating from the bulk of the crude as a consequence of the fluids movement towards the wellbore and the consequent drop in fluid pressure. An eco-friendly nano-fluid was developed and pilot treatment conducted in February 2014, which successfully rejuvenated the well back to production. Subsequent treatment was conducted in early 2018 on the same well and later replicated on another well as part of technology maturation process. This paper incorporates laboratory tests conducted to customize the nano-fluid, engineering approach on the treatment volume, simulation analysis on treatment schedules, treatment procedure as guidance for offshore personnel and actual field result of the treatments. Remedial treatment for near wellbore HMWOD using novel nano-fluid has successfully revived the wells back to production. Further development and replication would open-up bigger opportunities to unlock potential of wells with similar organic deposit issue throughout PETRONAS' operation.

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During the low oil price era, the ability to deliver a small business investment yet high monetary gains was the epitome of success. A marginal field with its recent success of appraisal drilling which tested 3000bopd will add monetary value if it is commercialized as early as possible. However, given its marginal Stock Tank Oil Initially in Place (STOIIP), the plan to develop this field become a real challenge to the team to find a fit-for-purpose investment to maximize the project value. Luxuries such as sand control, artificial lift and frequent well intervention need to be considered for the most cost-effective measures throughout the life of field ‘Xion’. During field development study, several development strategies were proposed to overcome the given challenges such as uncertainty of reservoir connectivity, no gas lift supply, limited footprint to cater surface equipment and potential sand production. Oriented perforation, Insitu Gas Lift (IGL), Pressure Downhole Gauge (PDG), Critical Drawdown Pressure (CDP) monitoring is among the approaches used to manage the field challenges will be discussed in this paper. Since there are only two wells required to develop this field, a minimum intervention well is the best option to improve the project economics. This paper will discuss the method chosen to optimize the well and completion strategy cost so that it can overcome the challenges mentioned above in the most cost-effective approach. Artificial lift will utilize the shallower gas reservoirs through IGL in comparison to conventional gas lift. Sand Production monitoring will utilize the PDG by monitoring the CDP. The perforation strategy will employ the oriented perforation to reduce the sand free drawdown limit compare to the full perforation strategy. The strategy to monitor production through PDG will also reduce the number of interventions to acquire pressure data in establishing reservoir connectivity for the second phase development through secondary recovery and reservoir pressure maintenance plan. This paper will also explain the innovative approaches adopted for this early monetization and fast track project which is only completed within 4 months. This paper will give merit to petroleum engineers and well completion engineers involved in the development of marginal fields.