For almost a decade the Prudhoe Bay field on the North Slope of Alaska has produced at a yearly average offtake rate of 1.5 million stock tank barrels of oil per day. As the reservoir depletes and field gas-oil ratios (GaRs) increase, gas handling constraints make it difficult to achieve oil rate targets. The Western Production Optimization Model (WPOM) was developed by BPX to deliver an offtake strategy that maximizes oil rate while minimizing processed gas. The model is based on the "incremental GaR" concept, or the lowest GaR selection for the next incremental barrel of produced oil.

Atlantis is a giant oil field with challenges that require a multi-disciplinary and phased approach to reservoir development. Initial development focused on the better-imaged extra-salt segment of the structure after eight appraisal penetrations revealed over a 1,500 ft oil column contained in several high quality thick pay sands. Signals of the reservoir complexity that would be associated with Atlantis were seen from the beginning. The early wells found variable fluid contacts, fluid compositional variations, large previously undetected faults, and what turned out to be perched water. Development drilling continued while the facilities were being fabricated. The drilling results strengthened confidence that there were large inplace resources but heightened concerns about complexity. In response, the development plan was modified to include ocean-bottom-seismic, downhole-flow-control completions, and a second production drill center. Initial reservoir performance revealed sub-seismic baffles that resulted in lower stabilized well productivity and more complex compartmentalization than expected. Integrated analyses of static and dynamic data enabled the integrated team to demonstrate that recovery per well was similar to pre-drill expectation and modification to the development plan would allow sustained production growth. Challenges going forward include appraisal and development of remaining segments of the field to effectively grow production and extend production plateau, and efficient operation of the wells, subsea architecture and production facilities.

The accuracy and precision of well rates are paramount in reservoir management, well performance surveillance, flow assurance, and any third party processing arrangements. Rate allocation is traditionally based on well rate tests and downtime. This method is usually time-consuming and thus performed relatively infrequently. This could be inadequate for proactive asset management especially with wells that may produce in transient state.This paper discusses methodology to improve well rate allocation quality and save engineering time. In practice, many fields face some or all of the following challenges that are related to well rate allocation: 1) reservoir communication, 2) well interference, 3) changing skin factors or other near wellbore boundaries, 4) uncertainties around reservoir fluid properties, and 5) difficulty in obtaining well rate tests for a variety of reasons. For many intelligent wells, it is a common practice to install permanent downhole gauges which are playing critical roles in field management. This paper describes a framework on how to capitalize on the real time data from well pressure and temperature sensors and use the data in Integrated Asset Modeling (IAM) to allocate the well rate with enhanced accuracy, increased frequency, and reduced processing time.The paper uses Atlantis in Gulf of Mexico as an example to demonstrate this process. The real-time data supported model based allocation process becomes virtual flow meters for the intelligent wells. For Atlantis, field-wide allocation accuracy has been improved from previously +/-10% error using the traditional allocation method based on well rate test and downtime method to current +/-3% error using the new method. This paper also shows model maintenance is a journey that needs strenuous attention especially after water injections commences and more production wells come online.

Many horizontal miscible gas floods experience relatively low vertical sweep efficiency due to gravity segregation of the injected solvent and reservoir liquids. This is true for the Prudhoe Bay Miscible Gas Project (PBMGP) in which the enriched-hydrocarbon miscible injectant (MI) is expected to sweep only approximately 30% of the reservoir volume in the project areas. The Prudhoe Bay reservoir has a relatively thick oil column, high inter-sand vertical permeability, high net-gross, and is generally developed on 80 acre (324 = 103 m2) well spacing.An infill drilling project was implemented in the Northwest Fault Block (NWFB) area of Prudhoe Bay (Fig. 1) to improve solvent sweep efficiency and increase EOR reserves. This project differs from many EOR infill drilling projects in that most of the additional recovery is attributable to EOR, with minimal improvement in waterflood recovery.The infill project is feasible because the reservoir is relatively thick, and sufficient EOR reserves are obtained from miscible displacement around new injectors. A significant increase in flood rate can also occur, resulting in production acceleration. Results of the project will guide analysis of infill drilling in other EOR areas at Prudhoe. The Prudhoe Bay Miscible Gas Project is the world's largest enriched-hydrocarbon miscible gas flood, and is located in northern Alaska, USA.

Introduction This extended abstract describes the use of infill drilling to improve solvent sweep efficiency and EOR recovery in a gravity dominated WAG flood. Much of the incremental oil recovery in the Prudhoe Bay Miscible Gas Project (PBMGP) is displaced from a relatively small volume of swept reservoir surrounding each WAG injector. Solvent override occurs due to high vertical permeability and the large density difference between solvent and reservoir fluids. Solvent rises to the top of the reservoir or underneath shales, forming cone-shaped swept intervals around WAG injectors (Figure 1). Vertical sweep by solvent in gravity dominated WAG floods can be improved by increasing the viscous-to-gravity ratio1,2. A higher viscous-to-gravity ratio (HVGR) expands the solvent swept areas around the injection wells before gravity segregation occurs. However, little can be done in the PBMGP to reduce gravity forces, and water and solvent injection rates are currently near the maximum attainable. Reduced well spacing remains the only viable method to increase viscous-to-gravity ratio. Most of the benefit from reduced well spacing is due to displacing oil from new WAG cones around the new injectors.