An offshore gas field has been producing sand for a few years. Sand production has been closely monitored through acoustic flowline devices and a sand collection system installed on the platforms. Observation of sand production has triggered evaluation of whether to install surface desanders or complete future wells with downhole sand control. This evaluation requires a prediction of sanding rate over the reservoir life. The possibility of providing downhole sand control on existing wells was also evaluated in separate studies. Predicting sanding rate, particularly for gas fields, has been historically challenging, mainly because of the sporadic nature of sand production, inadequate quantification of fundamental physics, and lack of representative lab tests, and reliable field calibration. To tackle these challenges, four studies have been designed and executed, including 1) the development of a reliable log-based rock strength estimate; 2) the prediction of sanding rate over the reservoir life for a conservative well condition; 3) the evaluation of sand particle transport from the reservoir to the surface facilities; and 4) the estimate of potential erosion of platform facilities. The sanding rate prediction is based on extensive laboratory tests of four carefully selected whole cores, with gas and water flow. It has then been validated by field monitoring data from an acoustic flowline device on each producer and a sand collection system on the platforms. The studies have provided a prediction of future sand production, how much of the produced sand will be seen at the surface (and therefore how much of it will fall into the rathole), how fast various components of the surface facility will erode over the field life, and what will be the optimal completion strategy for sand control should it become necessary. They have provided input to an integrated evaluation of completion design, reservoir management, platform configuration, and field economics. Introduction For a long time sand production has been viewed as a cost source and a safety hazard for the oil and gas industry. It can erode downhole equipment and surface facilities, cause pipeline blockage, leakage, damage casing due to formation subsidence, lead to more frequent well intervention and workovers, and generate additional need for sand disposal. Since the 1980s, however, it has been consistently demonstrated that sand production could also be beneficial in both heavy oil reservoirs (Dusseault and Santarelli, 1989) as well as conventional oil reservoirs (Andrew et al., 2005). To allow sand production up to a certain level could result in a large amount of cost savings from the simplification or even elimination of downhole sand control. More importantly the removal of sand from the rock matrix could enhance the near wellbore porosity and permeability, promote oil mobility, and therefore increase production rate (Dusseault and Santarelli, 1989; Han et al., 2007). Economic benefits of avoiding complex and expensive downhole sand control have encouraged many oil and gas operators to select sanding strategies from a comprehensive evaluation of the sanding prediction, the equipment and facility tolerance, and the field CAPEX, OPEX, risk, HSE, etc. (Rawlins and Hewett, 2007), rather than simply reacting to the onset of sanding.

Summary An offshore gas field has been producing sand for a few years. Sand production has been closely monitored through acoustic flowline devices and a sand-collection system installed on the platforms. Observation of sand production has triggered evaluation of whether to install surface desanders or to complete future wells with downhole sand control. This evaluation requires a prediction of sanding rate over the reservoir life. The possibility of providing downhole sand control on existing wells was also evaluated in separate studies. Predicting sanding rate, particularly for gas fields, has been historically challenging, mainly because of the sporadic nature of sand production, inadequate quantification of fundamental physics, and lack of representative laboratory tests and reliable field calibration. To tackle these challenges, four studies have been designed and executed: (1) the development of a reliable log-based rock-strength estimate, (2) the prediction of sanding rate over the reservoir life for a conservative well condition, (3) the evaluation of sand-particle transport from the reservoir to the surface facilities, and (4) the estimate of potential erosion of platform facilities. The sanding-rate prediction is based on extensive laboratory tests of four carefully selected whole cores with gas and water flow. It then has been validated by field-monitoring data from an acoustic flowline device on each producer and a sand-collection system on the platforms. The studies have provided a prediction of (1) future sand production, (2) how much of the produced sand will be seen at the surface (and, therefore, how much of it will fall into the rathole), (3) how fast various components of the surface facility will erode over the field life, and (4) what will be the optimal completion strategy for sand control should it become necessary. They have provided input to an integrated evaluation of completion design, reservoir management, platform configuration, and field economics.

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.

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