The KN field in KM cluster is located approximately 200km offshore, at water depths ranging from 59–102m. The field is part of the KM Cluster Integrated Development Plan, where the primary objective for KN field development is to recover the reserve from fringing pinnacle reef carbonate reservoir, expected to be achieved through two deviated 7-inch open-hole monobore subsea wells. KN field is expected to deliver around 200 to 300 MMSCF/day to the LNG plant to help relieve an anticipated gas shortage, as such failure to deliver the target would definitely upset the gas supply. Besides cost savings, the shallow water subsea development concept is part of the company's long-term vision to train its staff with new technologies and prepare them with basic guidelines for future development especially in deepwater. Although this is already considered a norm in other parts of the world, subsea completion is relatively a new experience in the company operation. The open-hole sections were drilled using Potassium/Sodium formate fluids with calcium carbonate as weighting and bridging agent and later the wells were completed with Cessium formate. Based on extensive laboratory test, it was found that this formate fluids allow for thin mud filter cake that can be remove effectively with differential pressure alone, excluding the need for filter cake breaker. High rate acidizing was planned as contingency should the wells failed to deliver the targeted well deliverabilities. Based on transient simulation using OLGA, high rate clean-up were planned to ensure effective filter cake break-up, removing debris and confirming the technical potential of the wells. With high rate, the duration of well clean-up is shorter and effective thus saving rig time. This paper details the planning and execution towards achieving the successful project of KN field, the 1st subsea development in the company
Cleanup operations of gas wells are conducted when the well is kicked off and tested the first time. During cleanup, the drilling and completion fluids come out of the well along with the produced gas and associated liquids. The phenomena is transient in nature and minimum gas rate and time required for cleanup are key questions to be answered before embarking on the cleanup and subsequent well test operation. The knowledge of minimum gas rate and time required for cleanup can assist the engineer in deciding the well test package and make best use of the available time. In the current study, transient simulations of cleanup and MRT of three horizontal gas wells are conducted using a commercial multiphase transient simulator. Before the actual cleanup operations, simulations were conducted to estimate the cleanup time and to arrive at optimum beanup procedure to achieve best cleanup for a maximum gas rate constraint of 60 MMscf/D which is dictated by the size of well test package. After the cleanup and MRT operations were conducted, the operational data was used to tune the model. It was observed that the predicted temporal variations of gas rate and gauge temperature and pressure from the tuned model were in very good agreement with the measured values. The tuned model was then used to ascertain the degree of cleanup achieved from the actual cleanup and MRT operations and the model predictions showed that except the last 60 metres from the toe, the wells were completely cleaned of completion fluid. The poor cleanup in the last 60 metres was possibly because of 60 MMscf/D gas rate limit imposed by the size of well test package or resulting from poor contribution from the near-toe area. The study brings forth the significance of dynamic simulations in predicting and history matching gas well clean up operations and how dynamic simulations can provide an insight into the pressure and flow transients during cleanup. The knowledge gained from dynamic simulations can assist the engineer in deciding the well test package for gas wells to be cleaned up and in quantifying the cleanup achieved from an already conducted cleanup operation.
An offshore operator in Malaysia had run a completion string in a highly deviated 7-in. gas well. When continuous pressure build-up in the production casing annulus was observed during well clean-up, leakage in the completion system was suspected. After several attempts to mitigate the pressure build-up failed, the operator initiated further investigation, which confirmed the suspicion. Small tubing leaks that were allowing produced gas inside the tubing to seep through to the annulus were found. These leaks could have allowed the pressure to increase, and possibly, could have caused the casing to collapse. In order to produce through the annulus, the pressure would have to be vented. With the high demand of gas in Malaysia and since the rig was still at the location, the project team decided to initiate immediate recompletion of the project instead of waiting for a later intervention. This well is one of three wells completed to develop the FN field within KCL area, located approximately 200 km offshore from Bintulu. The field was expected to deliver up to 100mmscf/day per well to help relieve an anticipated gas shortage. This paper discusses the history of the wells, the diagnostic methods used to analyze the well problems, the pros and cons of each solution considered, details regarding the recompletion chosen, and the challenges encountered during the recompletion activities. The discussion also highlights the successful solution used for closing and reopening the fluid loss isolation barrier valve (FLIBV) with a wireline tractor rather than with other options considered after conducting a successful system integration test (SIT) prior to the project execution. The unique solution chosen was a first for Malaysia, and probably, for the world. The success of the recompletion results provided improvements for future applications and will be a benchmark solution for future operations.
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Formation evaluation quality and cost efficiency are crucial in ultra-deepwater reservoir evaluation. Reservoir properties such as fluid composition, formation pressure, and sand producibility are critical in the exploration and appraisal phases of the well life and represent a key input to comprehensive production and reservoir engineering studies in the development phase. In addition, contaminants measurement including hydrogen sulfide (H2S), carbon dioxide (CO2), and mercury are important to address challenges in the planning and utilization of equipment and production facilities. This work is based on recent experience in South-East Asia that demonstrate prudent operatorship in maximizing value of information (VOI) from exploration drilling and evaluation. These formation testing is conducted to address the inherent uncertainty in reservoir characterization; particularly reservoir connectivity, producibility and presence of fluid's contaminants. Integrated measurements such as core data, log analysis, image logs, pressure data and fluid sampling were utilized to better characterized the reservoirs. Advanced sampling method was conducted to evaluate presence of contaminants including H2S, CO2, and mercury in the reservoir. Onsite lab services were utilized to handle and analyze the captured sample on location for better contaminants evaluation. In addition, formation mini-DST testing was also conducted to further understand interval rock and pressure properties at larger scale. The application of this proposed approach is critical to reduce the subsurface uncertainty especially on reservoir and fluid properties; which inputs are used to prudently design future field development facilities. Field data and workflow demonstrating formation evaluation techniques will be presented in this paper. Lesson learned and best practice will also be explained supported by lab analyses and results.
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