A total system production optimization model has been implemented in a complex gas-lifted offshore operation, resulting in production gains and operating cost reductions. Whereas previous optimization models considered only the wells and production gathering network, the new model is able to consider the combined performance of the total system, including downhole well configurations, the complex production gathering and lift-gas distribution pipeline networks, separators, compressors and pumps. The model is applicable to most gas-lifted fields, and will be particularly beneficial when applied to those with complex production systems, and where compressors are a constraint on total system performance. The output from the optimization model principally comprises recommended values for individual well gas lift injection rates, separator pressures, compressor discharge pressures and compressor utilization. Field results are presented in the paper to demonstrate how implementing the optimizer's recommendations in the field resulted in economic benefits through increased production and reduced operating costs. Also described is how the model allows field operations engineers to re-optimize field control parameters on a more frequent basis and with less manpower than previously. The successful implementation of a complex model with such a broad scope is as dependent upon the implementation process as it is upon the technology. Therefore, in addition to describing the details of the model itself, this paper will cover the issues that arose during the implementation and how they were resolved. These include the level of manpower and support required, project organization and execution, and the processes required to sustain the benefits after the initial optimization gains have been realized. Introduction Dubai Petroleum Company (DPC) has implemented a production optimization tool that has yielded production gains and operating cost reductions. The field optimization software is used to model the complex production networks associated with the gas-lifted fields, including the downhole well configurations and the surface facility components such as gas compressor trains, pipelines and surface pumps. Key benefits realized from all fields were a 3% total production increase, a 4% reduction in lift gas requirements and a 3% reduction in operating costs. Field operations support was critical to the project's success by continuously tracking the operational parameters throughout implementation to validate the recommendations and results. The project was planned to be executed in three phases, including a pilot study, to assess the value of a full field model and to identify and resolve implementation challenges. The full field model was implemented during 2003 and produced several key learnings about the level of manpower and support required, the importance of accurate well model tuning, and the value that a detailed compressor model can add to a system highly dependent on compressor efficiency. Challenges associated with the gas lift control systems, which are nearing obsolescence, were also identified and created a need for alternative strategies depending on the length of time that the gas lift rate reallocation would be in effect. The full field optimization process utilizes an integrated approach to address operational challenges. A team of engineers and operations personnel now proactively manages events based on a well-defined strategy. The optimization model has allowed gas lift reallocations to be performed on a more frequent basis with less manpower. Based on these reallocations, production increases have been realized and the fields are currently operating at the historically lowest separator pressures. Offline studies have been performed to recommend process equipment modifications and justify major equipment overhauls. The integrated network model has also been used as a predictive tool to forecast the impact of ambient conditions and scheduled maintenance on production rates. The results are currently being monitored to determine the value of adding a fully automated interface to the system model software package.

The Alpine field located on the North Slope of Alaska was developed using open-hole horizontal completions drilled along the maximum principle stress and dominant fault orientation (northwest/southeast). Open-hole completions were considered the best completion option based on rock mechanics, improved profile surveillance and cost. The original Alpine field development plan did not include hydraulic fracture stimulation based on the reservoir characterization. Well performance had proven to be economic in this Jurassic, marine sandstone without hydraulic fracturing, until drilling the CD2–37 well in 2003. The poor reservoir quality found in the southwestern edge of the field required stimulation to produce at economic rates. A hydraulic fracture treatment was performed resulting in a 200% production increase. Over the past three years, a stimulation program has evolved with improvements in candidate selection, performance and predictability. Future plans include continuing to stimulate candidate wells by incorporating horizontal completion technologies that are more conducive to multiple fracture technology. This paper presents the evolution of the candidate selection process and a review of reservoir characterization as a result of the significant production improvements gained from hydraulic fracturing. We will also present how the Alpine full field model predictions have impacted the candidate selection process and discuss the stimulation design history that includes fracture fluid changes resulting from core analyses. Introduction The reservoir mechanism impeding maximum well deliverability was initially considered to be dominated by reservoir damage from brine imbibition based on core work comparing brine-based and oil based drilling fluids.1 Based on the 2005 core study results, avoiding exposure to brine or any other water based fluids was the standard mode of operation. For this reason, diesel based fracture fluids were used to perform the first three fracture stimulations. The first fracture stimulation was performed in 2004 on the CD2–37 well in a poor quality area of the reservoir on the southwestern edge of the field. The next two stimulation candidates selected in late 2004 and performed in 2005 were based on the thickness, reservoir quality and "skin damage" assumed to be present from using brine-based drilling fluids. The initial stimulation results were encouraging. Logistics is a large obstacle at Alpine due to "ice road only" access for fracture stimulation equipment and diesel transport to location. These logistic issues along with the increasing diesel fuel costs led the team to consider reviewing alternative fracture fluid systems to determine the impact on well performance versus continued use of diesel based frac fluids. Various fracture fluid systems were reviewed and a borate cross-linked low polymer loading system was selected based on the high retained permeability results. The six fracture stimulations performed in early 2006 returned incremental rates in excess of 100% over the predictions at sanction. Post-frac production results suggest that vertical communication through the entire reservoir section, achieved through fracturing, is a dominant mechanism for improved production performance. Connecting the stimulated wells in the full field model (FFM) to all grid cells above and below the estimated fracture length improved the prediction compared to previous PI or skin adjustment techniques. Using this methodology, the number of potential fracture stimulation candidates has increased by 200%.

Summary A total-system production-optimization model has been implemented in a complex gas lifted offshore operation, resulting in production gains and operating-cost reductions. Whereas previous optimization models considered only the wells and production-gathering network, the new model is able to consider the combined performance of the total system, including downhole well configurations, the complex production-gathering and lift-gas-distribution pipeline networks, separators, compressors, and pumps. The model is applicable to most gas lifted fields and will be particularly beneficial when applied to those with complex production systems, and those where compressors are a constraint on total-system performance. The output from the optimization model principally comprises recommended values for individual-well gas lift injection rates, separator pressures, compressor discharge pressures, and compressor use. Field results are presented in this paper to demonstrate how implementing the optimizer's recommendations in the field resulted in economic benefits through increased production and reduced operating costs. Also described is how the model allows field operations engineers to reoptimize field control parameters on a more frequent basis and with less manpower than previously. The successful implementation of a complex model with such a broad scope is as dependent on the implementation process as it is on the technology. Therefore, in addition to describing the details of the model itself, this paper will cover the issues that arose during the implementation and how they were resolved. These include the level of manpower and support required, project organization and execution, and the processes required to sustain the benefits after the initial optimization gains have been realized. Introduction Dubai Petroleum Company (DPC) has implemented a production-optimization tool that has yielded production gains and operating-cost reductions. The field-otpimization software is used to model the complex production networks associated with the gas lifted fields, including the downhole well configurations and the surface-facility components such as gas-compressor trains, pipelines, and surface pumps. Key benefits realized from all fields were a 3% total production increase, a 4% reduction in lift-gas requirements, and a 3% reduction in operating costs. Field operations support was critical to the project's success by tracking the operational parameters continuously throughout implementation to validate the recommendations and results. The project was planned to be executed in three phases, including a pilot study to assess the value of a full-field model and to identify and resolve implementation challenges. The full-field model was implemented during 2003 and produced several key learnings about the level of manpower and support required, the importance of accurate well-model tuning, and the value that a detailed compressor model can add to a system highly dependent on compressor efficiency. Challenges associated with the gas lift control systems, which are nearing obsolescence, were also identified and created a need for alternative strategies depending on the length of time that the gas lift rate reallocation would be in effect. The full-field optimization process uses an integrated approach to address operational challenges. A team of engineers and operations personnel now manages events proactively on the basis of a well-defined strategy. The optimization model has allowed gas lift reallocations to be performed on a more frequent basis and with less manpower. On the basis of these reallocations, production increases have been realized and the fields are currently operating at the historically lowest separator pressures. Offline studies have been performed to recommend process-equipment modifications and justify major equipment overhauls. The integrated network model has also been used as a predictive tool to forecast the impact of ambient conditions and scheduled maintenance on production rates. The results are being monitored currently to determine the value of adding a fully automated interface to the system-model software package.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe development of the Eumont gas play in Lea County, New Mexico created unacceptably high operating costs associated with gas well production.Two major issues were economically producing low pressure gas wells (1.5-2 psi/100 feet) with low connate water production and proppant production. The first choice for artificial lift once loadup occurred was beam pumps. Sand production and low fluid volumes however forced a paradigm shift to evaluate plunger lift as an alternative based on the low fluid volumes and low bottom hole pressures. The end result has reduced operating costs by over 70% in the areas that plunger lift has become the primary artificial lift method and reduced the lease expense per BOE by 25% over the 2-1/2 year implementation period. This paper discusses the steps taken to apply basic plunger lift concepts and progresses to the current plunger lift system that incorporates annular flow to minimize bottom hole pressure; therefore maximizing production. Evidence will be presented to validate that switching from beam pump to plunger lift has on average increased production. Integrating this "new found" technology on high GLR oil wells has been beneficial as well.