Design, Implementation and Performance of a Down-Dip WAG Pilot

Abstract Water-alternating-gas (WAG) injection is an enhanced oil recovery (EOR) method aimed at increasing sweep efficiency by contacting zones that are not adequately swept by water injection and by increasing microscopic displacement efficiency as gravity-aided WAG injection often gives lower remaining oil saturation. WAG performance also depends on whether it is updip or down-dip injection. Most WAG case studies available in the literature are up-dip WAG injection and most fields with WAG are in North America. This paper will present a case study of down-dip WAG in a field offshore West Africa. Field E is located offshore West Africa. Production from the gently dipping reservoir started in December, 2006 with peripheral water flooding as a primary recovery method. A WAG injection pilot was implemented in a down-dip injector in June, 2009. The main motivation for WAG injection was to reduce gas flaring with a secondary objective of improved oil recovery. Design, implementation and surveillance of the WAG pilot required a multi-disciplinary approach. Coordination between the subsurface and the operations teams was key to ensure timely implementation of the WAG pilot as per the design including subsequent data gathering. For WAG pilot design, a full-field simulation model was built and history matched. Sensitivity runs were made to optimize fluid injection rates and WAG cycle size to reduce flared gas volumes without having a negative impact on recovery. Conversion of a down-dip water injector to WAG required minimal facilities modifications. A comprehensive reservoir surveillance plan was developed to monitor WAG performance. Surveillance results to date indicate down-dip WAG is having a positive impact. Based on encouraging results and on updated simulation modeling, the WAG pilot has been expanded to another injector. The paper will discuss details of down-dip WAG pilot program design, implementation, surveillance and performance. Introduction Field E was discovered in May 2001. The exploration well encountered oil-bearing turbidite sands of Campanian (Upper Cretaceous) age. To date several exploration and appraisal wells have been drilled in and around the area, identifying multiple, normally-pressured hydrocarbon accumulations. Field E is located on the present day continental shelf in ~65 m of water at an average reservoir depth of 1,000 m. Seismic mapping (Figure 1) identifies two meandering canyons. The North-East canyon (E canyon) is where Field E is located. It is a gently dipping reservoir with dip angle varying from 5º to 10º. A cross-section through Field E is shown in Figure 2. There are several mapped faults. Based on the field performance, these faults are acting as baffles to fluid flow. Trapping in Field E is primarily stratigraphic with some local structural fault intersection closures.