Remaining oil saturation (ROS) and waterflood residual oil saturation (Sorw) are key parameters for reservoir modeling and waterflood management in a group of heterogeneous deepwater turbidite reservoirs. A large amount of laboratory special core analysis (SCAL) data indicated high Sorw values and a large target potential target for chemical EOR (enhanced oil recovery). Available SCAL data was not considered reliable. Acquiring additional core was considered to be too costly and too risky due to the highly deviated well paths required for new wells. Single Well Chemical Tracer Tests (SWCTT's) in producing wells were the only viable alternative. This paper describes – to our knowledge – the first applications of SWCTT in a deepwater setting. An early 2010 SWCTT showed ROS / Sorw to be much lower than expected but test interpretation was uncertain. The 1st SWCTT provided a valuable learning experience to improve test design and execution and to improve on significant logistical challenges in the deepwater setting. Using lessons learned we performed two additional SWCTT's in late 2010. The later SWCTT's included well integrity pre-tests and smaller completion intervals. Typical SWCTT volumes were ~5,000 bbl of seawater containing tracers with a depth of investigation of ~4 to 5 meters. All three SWCTT's indicated low Sorw values, ranging from 0.05 to 0.20 with a nominal average of 0.15. Similar results from all three SWCTT's indicate that microscopic displacement efficiency is very good; eliminating the option of chemical EOR. The current field development plan is focused on improving volumetric sweep efficiency. Properly designed and executed SWCTT's can be considered as large-scale "laboratory waterflood tests" at true reservoir conditions (e.g., live oil, wettability and stress history). Compared to conventional SCAL tests using small plug samples, SWCTT's see a much larger rock volume and avoid wettability alteration issues that plague modern cores taken with OBM (oil based mud). Though logistically challenging in deepwater, SWCTT's can be more cost- and time-effective than taking a new core.

Ebano field is a high permeability slope-channel turbidite reservoir located offshore Equatorial Guinea, West Africa. Oil production from this field started in May 2009 and water injection began in July 2009. Currently, the field operates with two wells; one injector and one producer with a well spacing of 1.5 km. Water breakthrough was observed approximately one year after water injection began, which was much earlier than the original prediction suggesting presence of water injection thief zone(s). Several reservoir management strategies to improve sweep efficiency were considered for implementation in this field including a reservoir in-depth waterflood conformance technology using a thermally active polymer (TAP). This paper will summarize the TAP pilot design, implementation, and performance interpretation based on a comprehensive surveillance program. The paper will also describe the workflow utilized to evaluate the technical feasibility of TAP technology (supported by detailed engineering, laboratory, and simulation studies).Engineering and laboratory studies to evaluate the technical feasibility of TAP started September 2010 and TAP pilot implementation commenced April 2011. Injection of TAP treatment was done from a barge requiring significant coordination between offshore and onshore to ensure safe handling and injection of chemicals. A total of 48,000 bbl of TAP were injected at an injection rate of 6,000 bbl/d, using a concentration of 15,000 ppm (4 cp injected). This treatment has been one of the largest offshore implementation using TAP technology. A detailed surveillance plan was put in place that included gathering and detailed analysis of injection/production data, injection pressure, produced water compositional analysis, production logs (PLT), and Fall-Off Tests (FOT) before and after the TAP treatment.Ebano pilot results validated TAP displacement and activation away from the injector. PLT data showed that the injection profile remained unaltered post treatment. Time-lapse FOT proved to be very useful in monitoring TAP performance. Uncertainties relating to how far away from the injector TAP was fully activated, injection pressure response (simulation vs. field), and production performance will also be addressed.

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.

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