The company and a vendor teamed up to optimize the gas-lift injection process in offshore dual string oil wells in BM, Malaysia. This paper outlines how the real-time production data and well model approach help to overcome the challenges faced in dual string gas-lift wells and to improve their performance. There are many challenges to manage a brownfield specially to get high quality data. Challenges include -• Integration of various data sources, improving data quality and automation of engineering workflows.• Calculation of well Inflow Performance Relationship (IPR) as composite IPR for commingled flow when reservoir information is limited. • Evaluation of high producing Gas Oil Ratio (GOR) wells using gas-lift diagnostics.• Computation of the injected gas allocation factor in dual-string wells when both strings are producing. It was a daunting task to find technology capable of integrating the different data sources and data structures without duplicating information. In addition, the technology has to be smart enough to feed data automatically to the engineering processes and create various well monitoring reports and alarms. This is so that well KPIs (Key Performance Indicators) based on well performance analysis are always available for further diagnosis and analysis to help engineers make informed decisions at the right time.For well performance analysis, a thorough knowledge of reservoir information is essential to determine reservoir deliverability. Not every well has complete reservoir information available. A composite IPR is built at the solution node where fluid from all producing layers is commingled. This helps to manage uncertainty on the reservoir side in multiple completion wells. In high producing GOR wells, a well-model based gas-lift diagnostic technique is used to correct GOR value analyzing the gas-lift performance (GLP) curve and thus helps to optimize the gas injection rate in the well and improves the well performance. Also, in dual-string wells, the gas-lift injection allocation factor is a key element of the gaslift optimization (GLO) process as both strings have a common gas injection source (i.e. common annulus). A method is developed to compute the gas injection rate in each string, based on well tests, to determine the gas-lift injection allocation factor. Currently, this well model based method is being tested and reviewed prior to full implementation in the field.Additionally, a well-model based Virtual Metering (VM) workflow is developed to estimate daily production rates in the absence of daily flow measurements. Models are validated using the sporadic well test and both Static Gradient Survey (SGS) and Flowing Gradient Survey (FGS). Valid models are used to predict the well performance on a daily and monthly basis which ensures effective well and field monitoring and surveillance processes.

Field B, located offshore Malaysia is heavily reliant on gas lift due to the high water cut behavior of the reservoir coupled with low-medium reservoir pressure. The field faces a challenge to efficiently execute production enhancement activities due to its low effective man-hour, a drawback of unmanned operation philosophy. The recent oil price downturn further exacerbates the limitation and calls for an innovative approach to continue the effort for maximizing oil recovery. As majority of the producing wells are gas-lifted, Gas Lift Optimization (GLOP) is an integral part of Field B's routine production enhancement job. The previous practice of GLOP involves data acquisition process of surface parameters and wireline intervention to collect Bottomhole Pressure (BHP), mainly Flowing Gradient Survey (FGS). Relying on wireline intervention limits the number of gas lift troubleshooting activities due to the low man-hour availability. To address this constraint, CO2 Tracer application was implemented in a campaign to supplement Field B GLOP effort. CO2 Tracer is a technology whereby concentrated CO2 is injected into the gas lift stream via the casing. CO2 returns are collected at the tubing end and utilized to diagnose the gas lift performance. The CO2 Tracer campaign was successfully executed in Platform A, B and C, covering 58 strings within an effective period of 3 months. This achievement is a milestone for the field as it opens a new approach in GLOP data acquisition process. Several advantages observed by executing this campaign is as follows: Multiplication of opportunities generation due to quick and simple operations of CO2 Tracer survey compared to wireline intervention for FGS.Reduction in HSE risks and intervention-related well downtime due to minimal intrusive requirement for well hook-up.Better understanding of complex dual gas lift completion due to simultaneous survey execution.Supplement CO2 baseline measurement for flow assurance monitoring.Quick quality check on gas lift measurement device. This paper will discuss on the challenges at Field B to implement GLOP, technology overview of CO2 tracer, the full cycle process of the CO2 tracer campaign and results of the campaign. Several examples of the findings will also be shared.

This paper serves to share the success story of utilizing Carbon Dioxide (CO2) well tracer surveys to conduct gaslift optimization, resulting in identifying additional oil production of 650 bopd and gaslift savings of 8 MMscf/d. In field B, located in the East Malaysia Region, wells in production are mainly operated with the assistance of gaslift. With over 70 active strings requiring gaslift, this creates a predicament in data acquisition of each string through the conventional Flowing Gradient Survey (FGS) method for gaslift optimization. The main setback of performing FGS in each string includes prioritization of slickline intervention for data acquisition against production enhancement activity, operation windows availability and production deferment. From the CO2 tracer survey, the root causes of well lifting issues such as multi-pointing, Gaslift valves malfunctioning, and tubing leaks can be identified. The accuracy of gaslift injection rate transmitters and total gas output from well test separators are also established together with the gaslift split factor for dual string wells. In the CO2 well tracer campaign in field B, 55 surveys were conducted of which 21 were on single string and 17 performed on dual strings. Around 20-30 pounds of CO2 was injected into the gaslift injection line and its concentration recorded at the well head. Injected CO2 travels through the tubing-casing annulus into the tubing through injection point/s. The travel velocities inside the tubing and casing were used to back calculate the operating lift depths. By importing the results of the CO2 well tracer survey into a software, the exact depth of injection can be measured, and any indication of multi-pointing can be seen. Accurate gaslift modelling can be conducted by incorporating actual measured injected gas rate, well test rate at time of survey and single/multi-point depth obtained from the survey. The CO2 well tracer campaign has proven to provide effective and reliable data on the lift gas entry points in the well, especially for fields with large number of gaslift strings. A total of around 650 bopd oil gain with gaslift savings of 8 MMscf/d was identified and will be realized by conducting Gaslift Valve Change (GLVC). CO2 well tracer campaign should be considered for fields with high quantity of gaslift wells as an alternative to FGS as it requires minimum equipment hook-up, has minimal production deferment, and does not require invasive well intervention. A presentation and discussion of the successful results, limitations, best practices, and lessons learnt from the CO2 tracer campaign aspires to be additive to the production surveillance tools in the oil and gas industry by providing alternatives in data acquisition from the conventional FGS.

Abandonment is becoming a major focus as an operator and also by regulators with a single prominent objective – to reduce its overall operation expenditure. From an operator's perspective, striking balance between abandonment expenditures asset integrity, regulator's requirement and funding for growth projects is key to ensure safe & reliable operations, sustained growth and profatibility. Sarawak Oil (SK Oil) is a brownfield operator with a huge number of legacy asset; some reaching more than 40 years of age. These assets are constantly being monitored closely for any integrity issue that might emerge due to assets operating beyond their original design life. There is also major development project currently on going which requires huge investments each year. These projects are vital to sustain the positive cash flow for SK Oil operations. Thus, there is a need to diligently balance between the expenditure for growth projects, routine operations and abandonment activities. In view of the business & operational requirements, a comprehensive abandonment execution outlook, stretching out until the end of field life was developed. The main consideration is the total free cash flow taking into account investments for development projects. The basic formula isOperating Cash Flow minus Capital expenditure where the balance will be used to fund abandonment activities. Another key consideration is the stakeholder management, agreement and consensus have to be met with these partners as well. Thus, the phasing strategy is crucial in determining the prioritization of the candidates which are due for abandonment to ensure minimal cash outflow for a non-cash generating activity. SK Oil has developed an abandonment roadmap which narrows down to the next five (5) years abandonment outlook. This roadmap has been presented to the regulator and has been agreed upon. Thus, this five (5) years abandonment outlook will be a guiding principle to plan for the actual abandonment execution. This paper is intended to highlight the approach in developing an abandonment database and key criteria that has been considered to phase out the abandonment activities. This paper is beneficial to operators that manage a huge high number of assets with mostly aging facilities, which need to be abandoned in order to reduce the operating expenditure in the long run.

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.