D. W. van Batenburg

Injectivity Experiences and its Surveillance in the West Salym ASP Pilot

ASP or polymer flooding in reservoirs with permeabilities below 100 mD has not been often applied due to the perceived and/or potential issues related to the injection of viscous polymer solution under those conditions. Poor injectivities become an even bigger issue if injection under matrix conditions is required. This is usually the case for pilot projects with relatively short inter-well distances to optimize response time, project costs and pilot duration. One of the major problems that could lead to injectivity deterioration is plugging of the formation in the near wellbore due to trapping of polymer molecules in smaller pores and polymer adsorption. The higher injected fluid viscosity due to polymer also leads to higher injection pressures. The injection pressure should, however, not exceed the formation breakdown pressure if matrix conditions are required. A proper flood design should achieve the compromise between polymer molecular weight, its concentration, viscosity of injected solution and injection pressure, and should include appropriate plans to mitigate injectivity loss. The paper describes the injectivity challenges experienced during water, ASP and subsequent polymer injection in the West Salym ASP pilot. The project is implemented in a sandstone reservoir with permeabilities in the range from 10 mD to 100 mD. Conventional waterflooding in West Salym is performed under fracturing conditions, hence it was recognized from the beginning that the injection of ASP and polymer solutions under matrix conditions in the pilot would be challenging. The paper provides the injectivity history for the pilot wells, describes the surveillance methods used, and provides details on the steps taken to improve the injectivity. New analysis approaches to effectively extract information contained in the real-time data that were developed for this project are also discussed. Overall, this paper will provide the reader with hands-on experience in injection of ASP and polymer solutions in reservoirs with permeabilities below 100 mD.

Ammonia as Alkali for ASP Floods – Comparison to Sodium Carbonate

Ammonia is logistically preferred over sodium carbonate for alkaline-surfactant-polymer enhanced oil recovery projects (ASP) due to its low molar mass and the possibility for it to be delivered as a liquid. On an offshore platform space and weight savings can be the determining factor in deciding whether an ASP project is feasible. Logistics may also be critical in determining the economic feasibility of projects in remote locations. Ammonia as alkali together with a surfactant blend of alkylpropoxy sulfate – internal olefin sulfonate (APS/IOS) functions as an effective alkali. Surfactant adsorption is low and oil recovery in core floods is high. Static adsorption tests show that low surfactant adsorption is attained at pH > 9, a condition that ammonia satisfies at low solution concentration. It is expected that ammonia has a performance deficiency relative to sodium carbonate in that it does not precipitate calcium from solution. Calcium accumulation in the ammonia ASP solution will occur due to ion exchange from clays. The high oil recovery for ammonia and the calcium accumulation in ASP and SP core floods with APS-IOS blends shows that this surfactant system is effective and calcium-tolerant. Also, phase behavior and IFT measurements suggest that APS/IOS blends remain effective in the presence of calcium. EO/PO sulfates (such as the employed APS) are known commercially available, calcium-tolerant surfactants. However, due to hydrolysis sulfate-type surfactants are suitable for use only in lower temperature reservoirs. Very different behavior was noticed for phase behavior measurements with calcium intolerant surfactants such as alkyl benzene sulfonates (ABS) and internal olefin sulfonates (IOS). In this case calcium addition results in a very high IFT and complete separation of oil and brine. Presumably this will result in low oil recovery. A preferred approach for ASP offshore with divalent ion intolerant surfactants may be the use of a hybrid alkali system combining the attributes of sodium carbonate and ammonia. The concept is to supply the bulk of the alkalinity for an ASP flood by ammonia with all the inherent logistical advantages. A minor quantity of sodium carbonate is added to the formulation to specifically precipitate calcium ions.