This paper presents a case history on new sandstone acidizing technology using a nonhydrofluoric formulation to successfully treat a high carbonaceous sandstone formation. The improved understanding of the chemical complications of hydrofluoric (HF) on dirty sandstones led to the design of a nonhydrofluoric treatment on the high carbonate content (dirty) sandstone formation. Previous treatments using various formulations of HF acid failed to remove the high skin associated with several wells in this formation. A new approach was taken to identify the damage mechanism and evaluate damage removal options based on the formation mineralogy. This approach analyzed the potential chemistry risks associated with using HF type treatments in the presence of particular mineralogies and temperatures. The new approach also used logging and reservoir modeling technology to forecast the estimated production profile of the complex multilayered formation. Candidate wells were identified by comparing the forecast production profile potentials to the surveyed production profiles based on production logging (PLT) of the prescreening candidates. The final treatment candidate was then selected for the trial of the new treatment formulation. The treatment was specifically tailored based on the identified mineralogy and encompassed the damage prevention strategies. The result was a 40% increase in oil production for the well, but a 2-fold to 10-fold increase for the treated zone, depending on pretreatment production assumptions. Introduction XJG oilfields are located offshore in the South China Sea around 130 km southeast of Hong Kong.1 The fields are composed of three geological structures named XJG 1, XJG 2 and XJG 3, the first one being discovered in 1984 and targeting sands from the mid-Miocene XH formation and finding up to 44 stacked reservoirs bearing black oil. Appraisal wells were drilled and tested; commercial production started in 1994 following the installation of two platforms. Oil gravity varies from 26° to 40° API, saturating unconsolidated sandstones with average porosity of 25% and permeability measured in a Darcy plus range. The formation is prone to produce sand, and typical completions at the beginning exhibited internal gravel packs inside a 9 5/8-in. casing, but recently shifted over to expandable sand screens in open hole making water control difficult to achieve. Reservoir pressure has been strongly supported by a bottom water drive aquifer, which has kept the pressure only a few psi below its original value. The water drive has helped to sweep hydrocarbons, but on the other hand, has also caused rapid breakthrough in high permeability layers. Electrical submersible pumps (ESPs) are used in all wells in the field to improve productivity and handle high volumes of water. Field average water cut at this stage is around 84% with a total field liquid production close to the limit of fluid handling capacity of the facilities. XJG reservoirs are being developed using two fixed platforms. As of this writing, all 24 available slots on platform XJG-2 have already been drilled and completed, while XJG-3 has one slot left available for an extended reach drilling (ERD) well in the near future. This situation limits the option of infill drilling to accelerate oil recovery. The combination of high permeable formation streaks and active aquifer accelerates water breakthrough in perforated zones, raising the average field water-cut. The oil production is near 85,000 BOPD while total fluid production is close to the 550,000 BFPD capacity of fluid handling and water disposal of the existing surface facilities on the platforms. Production logging is performed on a regular basis to monitor zonal fluid contribution. Reservoir zones are isolated by external packers and flowing through sliding side doors (SSD) valves. Water control is achieved by closing the SSDs to the high water-cut zones, but it is hard to determine exactly where the water is coming from or how much hydrocarbon has been left across the perforated intervals grouped in that zone.

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.

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