The Jasmine oil field, in the Gulf of Thailand, has several pools of unconsolidated sandstone reservoirs. Multi-zone completion is usually deployed in these reservoirs, however, sand control in this completion type could be a challenge. Several sand control techniques were evaluated and the most promising strategy was found to be chemical sand consolidation treatment. In the design phase, the most critical challenge was to determine the optimal and safe chemical recipe and placement technique. A single chemical recipe optimized for all of the reservoirs was achieved, yielding an unconfined compressive strength (UCS) of at least 500 psi while retaining a permeability of 40%. Bullheading was selected as the placement technique. To minimize contamination of the chemical with annulus fluid, we designed to shorten the distance between the packers of each completion zone. Cut-to-release packers were used instead of pull-to-release packers to mitigate the concern of unwittingly unsettling the packers. A risk assessment was conducted to cover all aspects of the job. High risk activity like pumping flammable fluids at high pressure was specifically singled out and special mitigation was put in place to ensure a safe execution of the activity. Some other mitigations such as minimizing nearby hot surface areas, real-time monitoring of oxygen levels, and purging the mixing system with CO2 were also considered. This paper provides a case study for chemical sand consolidation treatment from the view of an oil company and covers the full lifecycle of the application from concept selection to the finalized procedure, taking into account both technical and operational considerations. This research contributes to the public body of knowledge within the oil and gas industry with regards to an emerging technique for sand consolidation.
Operating Platong field in the Gulf of Thailand (GoT) is challenging because of the small compartmentalized reservoirs in the fluvial deposition environment. As the completion strategy has to be low cost in order to achieve the economic hurdle rate and the initial strategy is to develop to be a gas field, a lot of existing oil wells do not have the artificial lift system in place. Without artificial lift, most of the oil wells usually cease flowing in 2–6 months. Therefore, the artificial lift is crucial to prolong the well life in Platong. Gas lift currently plays a very important role in Platong field. With the continuous initiation and operation improvement, production from Platong gas lifted wells has been gradually increasing from 10% in June 2008 to 50% of total field production in June 2011. The subsurface challenge for gas lift mainly involves with the effort of cost reduction. Drilling and completion improvements from 2-trip to mono-trip gas lifted completion in 2008 reduces a rig time by ~1 day/well (from total ~7 to ~6 days/well). Converting the existing producers that are not equipped with gas lift mandrels was initially undertaken by installing coiled tubing gas lifted assemblies. This method was subsequently replaced with the installation of slickline run straddle pack-off gas lift assemblies in 2010 at a cost saving by -73%. In terms of the production operation aspect, proper gas lift candidate selection process, excellent collaboration between office and offshore are the key components for the success. Beyond the gas lift injection rate optimization, the surface challenge is mainly related to the optimization of the gas lift sources from the back pressure reduction systems, i.e. Remote Compressor (RC) and the mobile Well Unloading Unit (WUU). The RC functions in both back pressure reduction and providing the high pressure gas lift gas to the producers. Several efforts have been put on the RC unit optimization and modification to maximize gas lift rate, for example the RC inter-stage is modified to increase gas lift rate from 2 to 5 MMscf/d which resulted in the oil increase of +500 bopd/platform. In May 2011, the modified WUU that can provide high pressure gas lift was implemented to revive the platform that does not have the RC to provide gas lift with the incremental oil of +1,000 bopd/platform. In Q2 and Q4 2011, four main gas lifted platforms are scheduled to commence the gas lift injection from a gas supply pipeline, where the gas source is supplied from the Central Processing Platform (CPP). We walk away from the gas lift from RC due to the limited gas reserves on those four platforms. With the continued gas lift completion and operation innovations in both surface and subsurface, proper working process in place, sufficient gas lift trainings for all personnel, and excellent collaboration between office located subject matter experts (SMEs) and offshore production operators, gas lift could significantly prolong the well life and certainly increase the recovery; as a result, enhance the asset value.
The development of marginal volumes in the Jasmine field is part of Mubadala Petroleum's overall strategy to extend the field's life. This development is accomplished by progressively exploiting increasingly challenging prospects. This paper highlights two case studies to illustrate how Mubadala Petroleum has successfully developed marginal prospects to unlock the Jasmine field's remaining potential. Prospect identification begins with integrated subsurface studies focusing on contingent resources. Several studies were conducted to determine the right technology to mature these marginal prospects. These prospects often involve the requirement to drill Extended Reach Drilling (ERD) wells. This is due to the fact that some platforms are slot constrained, such that wells cannot always be drilled from the nearest platform. One of Mubadala Petroleum's solutions was to drill a horizontal well with a completion that uses an Autonomous Inflow Control Device (AICD) to optimize and enhance oil production. This combination of AICD and ERD horizontal wells has proven successful in the Jasmine field's continuing development. Two wells in this case studies were drilled during the 2018 and 2019 drilling campaigns, illustrate how marginal volumes are developed in the Jasmine field, with each case having unique objectives and challenges. In 2018, one horizontal well was drilled, with an aim to enhance recovery efficiency in the viscous oil reservoir. The well was drilled close to the top reservoir, AICD devices were installed in conjunction with a sand screen to delay water breakthrough, and the well has been in production for two years. The overall strategy was effective in delaying water breakthrough. In 2019, a horizontal well was drilled to develop a relatively small 14ft oil rim below a thick gas cap reservoir. This well was the longest ERD well in the Gulf of Thailand. The well was also successfully drilled and geosteered at 4-5 ft TVD below the gas cap. AICD's were installed to balance the gas cap expansion and aquifer support to optimize oil production. The well has produced at a stable oil rate of 500-600 bbls per day with minimal gas and water production, up to the present date, confirming the validity of AICD technology in reducing the production of unwanted fluids. The AICD has been shown to play a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. AICD completions also help to enhance production recovery from viscous oil reservoirs. Moreover, ERD drilling has improved the feasibility of several remote prospects and minimized the slot availability constraint in the Jasmine field.
This paper describes a collaborative analytical technique employed by a team of subsurface, production and facilities engineering members on improving production allocation in a mature field producing at a high water cut. The field production allocation deteriorated sharply from 2015 when a field water cut was beyond 90%. The paper describes the entire workflow starting with problem identification, preliminary investigation, key actions taken, and collaborative analytical techniques utilized and proposed solutions to improve production allocation. The team conducted a primary investigation using several key investigative techniques and the result led to the identification of two main focus areas to resolve the production allocation issue; a) Improving the existing production allocation method, and b) Improving the current well-test measurement procedure. The team developed collaborative analytical techniques including fit-for-purpose mathematical modelling, specific design for field experiments and advance nodal analysis, which used as a means of identifying the potential root causes in well-test measurement procedure. Following primary investigations, the allocation methodology was updated to include the export meter oil volume readings as an extra step in the allocation algorithm. This helped removing the impact of physical conditions (e.g. weather) from the variations of tank dip measurements. Following implementation in July 2017, results indicated a clear improvement on allocation factors up to 26% on two platforms. Unfortunately, the remaining platforms barely showed any improvement. This was in line with preliminary findings that had identified these platforms as contributing the most to the overall field allocation factor deterioration. On the well-test measurement procedure, the result of collaborative analytical techniques concluded that the current Basic Sediment and Water (BSW) measurement by centrifuge method being deployed in the field was acceptable for crude with a low water content, while it tended to underestimate BSW in wells producing at relatively higher water cuts. With this realization, correction factors were developed and recommended to be applied to the measured BSW to mitigate the measurement uncertainty. The applied correction factors were found to better reflect the actual oil rate from the wells and better match the oil volume measured at platform export meters. The result showed immediate improvements the overall field allocation factor by up to 21%. This collaborative analytical technique to improve production allocation was uniquely developed for a mature oil field producing with extremely high water cut and located offshore in the Gulf of Thailand. Although the collaborative analytical techniques consisted of fit-for-purpose mathematical modelling, specifically designed for the field in question and adaptive approach of nodal analysis, the methods can easily be replicated to other fields, with a number of simply quantifiable potential benefits.
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