Petroleum Development Oman operates a large number of heavy oil fields in the south of Oman.One of the fields is being developed with horizontal wells completed with sand exclusion screens and beam-pumps to produce the heavy crude oil to surface. Development drilling is in progress as per the field development plan requiring more than 10 wells to be drilled each year.The integrated asset team carried out a post production evaluation of the 2007 newly drilled wells. The evaluation identified five underperforming wells requiring further examination to establish cause of performance impediment and to devise ways to remedy the problem.The well performance modelling of the underperforming 2007 wells indicates very high skin values. This suggests the wells are severely damaged (e.g., reduced permeability) and/or only a fraction of the sand face is open to flow, suspect due to presence of mud filter cake. The high skin values are significantly impacting the gross fluid production consequently affecting net oil production from these wells.A wellbore clean up and stimulation treatment was designed and well interventions scheduled to remove the suspected mud filter cake, consequently improving well productivities. This paper reviews the production performance following wellbore clean up and stimulation of five underperforming wells. Covering well performance analysis, treatment design, execution methodology and post treatment results including the way forward to advance the current wellbore clean up process to deliver higher productivity wells in the upcoming 2009 and future drilling campaigns.

Majority of oil wells operated by Petroleum Development Oman (PDO) are produced by beam-pumps (BP). Average water cut in a number of fields in South of Oman reaches 95%. Increasing water production overloads processing facilities leading to handling and disposal constrains requiring wells to be shut-in. BP completions are not surveillance friendly making production logging to identify water entry for optimization (water shut-off) a challenge. The current technique to acquire production logs requires recompletion to dual-string completion to allow logging: BP short-string and surveillance conduit long-string. This is resource intensive, high cost, restricts production and limited to 9-5/8in. cased wells. Moreover, new wells are completed with dual 9-5/8in. × 7in. casing for well life-cycle integrity management. A novel solution was developed and part-funded by PDO consisting of a jet-pump (JP), 1in. inside 2in. concentric-coiled tubing (CCT) strings, power cable and production logging tools (PLT). This cost-effective real-time surveillance technique will facilitate routine production logging in BP wells, significantly reducing well intervention time and cost (50% reduction) as only the rod string is retrieved by light-hoist in preparation for logging. Wells completed with dual-string completions, which have previously been production logged were selected for field trial. These existing logs were used as a baseline for new log comparison. The technique was successfully deployed in a 3 well field trial campaign for the first time in southern oilfields (industry first). The new production logs compared very well to existing logs (same water signature observed), proving the techniques robustness to identify water entry in different production environments. We preset advantages of the new technique over conventional, candidate selection, logging tool options, interpretation methodology, field trial results and comparison logs. This new system is being deployed across PDO and is applicable to other fields being produced by BP, progressing-cavity pump (PCP) or electrical submersible pump (ESP) to identify water entry for production enhancement or reservoir monitoring.

SPE Gulf Coast Section Electric Submersible Pump Workshop, The Woodlands, Texas, 25–27 April, 2007 Abstract ConocoPhillips China Inc. (COPC) operates the Penglai 19–3 oil field, located offshore in Bohai Bay, the People's Republic of China. COPC holds a production sharing agreement with China National Offshore Oil Corporation(CNOOC). The Penglai 19–3 field is the second largest oil field in China with 3.8 billion bbl of oil in place, discovered in May 1999 and put on productionin December 2002. Electrical submersible pumps (ESPs) were selected as the most economic artificial lift method to develop the field, based on the reliability, flexibility and robustness to produce wells with high flow rates and lift heavyoil in an offshore environment. The first ESP installations were challenged with high free gas and excessives and production, resulting in operational issues and a number of failures. Even in this hostile environment, production peaked at 37,800 BOPD during November 2003, before declining as a consequence of reservoir pressure depletion. Moreover, the lower reservoir pressure increased the free gas, thereby reducing pump performance, excessive sand production lead to plugging of the pumping system and sand fill across the reservoir reduced productivity. Various enhancements to the completion and ESP system were made during subsequent well interventions improving ESP performance, maximizing and maintaining production from the field. Furthermore, performing continuous ESP data trend analysis and performance modeling enabled the artificial lift system to be analyzed and diagnosed to maintain optimum well performance. Collaboration between Operator and Service Provider through performance review meetings and changes to operational practices were also implemented. This paper reviews the operation, optimization, and performance of the ESP systems and the challenges faced during the first 3 years of production. Covering initial installations, subsequent well interventions, operation philosophy, optimization methodology, case studies demonstrating value of gas separation and handling devices, completion improvements, ESP configuration enhancements, run life assessment and equipment dismantle findings.

The oil field was discovered in 1976 in southern Iraq and began production in 2001. Shell (operator) and partners were awarded a development and production service contract in 2010 to fully develop the field. First commercial production was achieved in 2013. To effectively manage the wells and reservoir, quality subsurface data is essential but acquisition of this data often leads to oil deferment. With limited spare well production capacity and inability of the processing facility to handle produced water, deferment from dry oil producers is resisted. In 2014, only 28% of the planned well reservoir and facility management (WRFM) activities were delivered generally because of 12 hours a day operations mode, which further escalates deferment for each activity. Limited time had resulted in cases where data quality had not met the team's expectation and longer surveillance activities such as bottomhole pressure build-up surveys could not be accommodated. Decision was made for the completion and well intervention (CWI) team to operate 24 hours a day to efficiently deliver the planned activities. Various equipment and procedure changes were implemented to further increase operational efficiency to deliver the work plan, reduce cost and minimize oil deferment. CWI carried out comprehensive 24 hours operational hazard analysis covering; emergency response plan for night operations, journey management for night driving and personnel night defensive driver training. Furthermore, set-up office-based CWI Engineering Team for planning and front-end engineering for WRFM activities, and 24 hours field supervision capability, secured commitment for 24 hours service company personnel coverage. Collaborated with WRFM team to provide personnel to support 24 hours operations for data QA/QC, production operations team to handover/hand-back wells during night to minimize deferment, logistics team for catering, security and diesel for 24 hours operation, maintenance team for light towers and maintenance manpower, and contract and procurement team for 24 hours operations contract rates. By end 2015, more than 100 WRFM activities were executed, tripling the number performed in 2014 with 25% less oil deferment through spending fewer days on wells and 20% budget saving due to gains in operational efficiency and better contract rates. By efficiently executing the WRFM optimization activities, double the production gains was realized sooner assisting in maintaining production levels. The planned data was received on time allowing improved reservoir monitoring and understanding for full field development. Moreover, data quality had improved considerably especially for flowing surveys that required longer flowing period to reach stabilization. Furthermore, training and progression of Iraqi Engineers from supervisors-in-training to autonomous wellsite supervisors. This paper presents how significant gains in operational efficiency were achieved ensuring delivery of business objectives; maintaining daily production levels, minimizing oil deferment, acquiring subsurface data for reservoir monitoring and increased understanding while retaining an excellent safety record. Also, sharing of best practices and lessons learned.