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Angsi Field is an offshore field located in offshore Peninsular Malaysia, developed with an integrated oil and gas processing plant, water injection facilities and gas lift infrastructure. The field was brought to oil production at an initial rate about 30 Mstb/d in end 2001. In early 2002, it started gas production at an initial rate of about 300 MMscf/d of gas which is currently maintained at about 300–400 MMscf/d. Crude oil production peaked in 2005 and was followed by a moderate decline over the next three years. Besides crude oil and gas production, the field also produces condensate while producing gas. It was recognized that a proactive field management strategy was required in order to minimize any further production decline and maintain excellent production operations as the field production forecast showed a declining trend. Four key levers for sustaining Angsi's production were identified, namely:prudent reservoir management and reliable water injection;continuous production improvement and unfailing well integrity;facility optimization and operational improvement; andmaintenance of high equipment uptime and infrastructure integrity. On top of those four levers, prudent and integrated production planning was very important in managing the integration of sub-surface and surface aspects. Various sub-surface and surface technologies were sourced with a target of sustaining production and maximizing oil and gas recovery. The look-back analysis presented here describes the use of an integrated approach in production planning and creativity in resolving problems involving reservoir management & well integrity and production operations through teamwork building. Introduction The Angsi Field is located 165 kilometers east of the Kertih coast line in water depth of 70m. The field is developed under the terms set forth in the Gas Production Sharing Contract ("GPSC") between PETRONAS Carigali Sdn Bhd ("Carigali"), ExxonMobil Exploration and Production Malaysia Incorporation ("EMEPMI") and Petroliam Nasional Berhad ("PETRONAS"), the national oil corporation of Malaysia. The field was discovered by drilling Angsi-1, a wildcat well offshore Terengganu, Peninsular Malaysia in 1974, followed by the first three appraisal wells drilled in 1995 and the second two appraisal wells drilled in 1997. The oil is produced from Sand Group I while the gas is produced from Sand Groups I and K. Water injection was identified as the suitable method for reservoir pressure maintenance from the first day of production with a voidage replacement ratio (VRR) target of one. Wells at the Angsi field typically have dual completions and multiple packers to allow sequential or commingled production from multiple zones. This strategy has been implemented to reduce the number of wells while maintaining a high number of drainage points. Prior to mid-2006, the Asset Base management approach was applied where production planning of the Angsi Field, was taking role in managing the exploration and production of Angsi Field and three other blocks in the region. To sustain competitiveness and resilience against the changing business landscape, the Asset Base approach was subsequently replaced by the Functional Base management method. Since then, some changes were made to suit the new functional base.
Angsi Field is an offshore field located in offshore Peninsular Malaysia, developed with an integrated oil and gas processing plant, water injection facilities and gas lift infrastructure. The field was brought to oil production at an initial rate about 30 Mstb/d in end 2001. In early 2002, it started gas production at an initial rate of about 300 MMscf/d of gas which is currently maintained at about 300–400 MMscf/d. Crude oil production peaked in 2005 and was followed by a moderate decline over the next three years. Besides crude oil and gas production, the field also produces condensate while producing gas. It was recognized that a proactive field management strategy was required in order to minimize any further production decline and maintain excellent production operations as the field production forecast showed a declining trend. Four key levers for sustaining Angsi's production were identified, namely:prudent reservoir management and reliable water injection;continuous production improvement and unfailing well integrity;facility optimization and operational improvement; andmaintenance of high equipment uptime and infrastructure integrity. On top of those four levers, prudent and integrated production planning was very important in managing the integration of sub-surface and surface aspects. Various sub-surface and surface technologies were sourced with a target of sustaining production and maximizing oil and gas recovery. The look-back analysis presented here describes the use of an integrated approach in production planning and creativity in resolving problems involving reservoir management & well integrity and production operations through teamwork building. Introduction The Angsi Field is located 165 kilometers east of the Kertih coast line in water depth of 70m. The field is developed under the terms set forth in the Gas Production Sharing Contract ("GPSC") between PETRONAS Carigali Sdn Bhd ("Carigali"), ExxonMobil Exploration and Production Malaysia Incorporation ("EMEPMI") and Petroliam Nasional Berhad ("PETRONAS"), the national oil corporation of Malaysia. The field was discovered by drilling Angsi-1, a wildcat well offshore Terengganu, Peninsular Malaysia in 1974, followed by the first three appraisal wells drilled in 1995 and the second two appraisal wells drilled in 1997. The oil is produced from Sand Group I while the gas is produced from Sand Groups I and K. Water injection was identified as the suitable method for reservoir pressure maintenance from the first day of production with a voidage replacement ratio (VRR) target of one. Wells at the Angsi field typically have dual completions and multiple packers to allow sequential or commingled production from multiple zones. This strategy has been implemented to reduce the number of wells while maintaining a high number of drainage points. Prior to mid-2006, the Asset Base management approach was applied where production planning of the Angsi Field, was taking role in managing the exploration and production of Angsi Field and three other blocks in the region. To sustain competitiveness and resilience against the changing business landscape, the Asset Base approach was subsequently replaced by the Functional Base management method. Since then, some changes were made to suit the new functional base.
Talisman Energy currently operates and pilots wells in frontier areas for shale gas development. Wellbore stability, and well control issues are the largest contributors to additional costs and non-productive time (NPT) while drilling exploratory, outpost, and wildcat wells. This is a hindrance to many logging and evaluating functions in pilot wells, which are critical to assessing future development decisions. Offset wells are relied upon to guide drilling decisions but in many exploration and frontier areas the nearest relevant offset well may be far away to even be geologically or structurally analogous. Tighter budgets, lower commodity costs, and commitment to lean culture mean that wells need to be drilled with as few surprises as possible by continuously executing the ‘no drilling surprises’ model adapted by other companies. This can be accomplished through continuous improvement cycles and collaborative approach between drilling and sub surface teams. In Talisman's frontier areas, the only laterally extensive sub surface data available before a well is drilled is 2D seismic. Although sometimes overlooked, this can provide critical data about the structural features that might contribute to drilling NPT. An example could be subtle structures that might cause the well to deviate more than normal due bedding inclination or drastic changes in bed dips due to structure. Using a combination of seismic interpretation and geomechanical software, we have been able to accurately predict shear failure and pore pressure gradients along with geohazards that correlate to actual drilling events in pilot wells. This is done to predict a safe mud weight window, horizontal stress directions, and magnitudes for easier drilling operations. Usually, there is a critical disconnect from prognosis to execution. To avoid this problem, the same team that assists the asset in the wellbore stability modeling monitors the drill and makes recommendations to the drilling team as events occur. In shale gas operations, where pilot wells are critical to the assessment of long term development, accelerating the learning curve is essential. Through this collaborative approach between the asset, geomechanics, real time monitoring, and the drilling operations teams; we have been able to drastically reduce well time and costs.
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