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Polymer Injectivity De-risking for West Salym ASP PilotNormal access

Authors: D. Wever, V. Karpan, G. Glasbergen, I. Koltsov, M. Shuster, Y. Volokitin, N. Gaillard and F. Daguerre
Event name: IOR 2017 - 19th European Symposium on Improved Oil Recovery
Session: Pilot & Field Cases
Publication date: 24 April 2017
DOI: 10.3997/2214-4609.201700241
Organisations: EAGE
Language: English
Info: Extended abstract, PDF ( 1.88Mb )
Price: € 20

Summary:
In the West Salym field, a mature waterflood is ongoing with increasing water cuts and declining oil production. To counter the decline a tertiary oil recovery technique called Alkaline-Surfactant-Polymer (ASP) flooding was selected. According to earlier studies the potential incremental oil recovery factor due to ASP injection is 15-20% of the ASP-targeted field STOIIP. An injection/production pilot to demonstrate the oil recovery potential of ASP technology and to obtain information for decisions on the subsequent commercial ASP projects was started in February 2016. ASP injection started in July 2016. The pilot area was developed with a 5-spot well pattern: 4 injectors connect to a single producer through the 15-20 m thick sandstone formation with permeabilities varying from 10 to 100 mD. Because of the short inter-well distance matrix conditions were required for the injection. This requirement in combination with the relatively low permeability of the reservoir rock resulted in the recognition that loss of injectivity is a major risk for the project. This paper focuses on de-risking polymer injectivity for both the ASP and polymer chase injection. We discuss the selection of the polymer type, molecular weight and concentration, specification of the water quality and chemical preparation procedures that are all important to minimize the risk of injectivity decline. Additional experimental work that was performed to qualify filtration of the polymer solution using a very small filter sizes is described. During long term injection experiments in both representative outcrop and reservoir material continuous pressure increase indicating permeability loss was initially observed. In investigating possible causes and feasible mitigations for the loss of injectivity different scenarios were tested. Both pre-shearing the polymer, pre-filtering the solution and different ways of preparing were tried and resulted in better results. A step change was made when dissolving the polymer in higher pH solution resulting in filtration ratios close to 1 and good injectivity in representative core material. Furthermore, in close collaboration with the polymer vendor, ways were found to improve the polymer quality in the manufacturing process in order to meet our strict specifications. Finally the laboratory results and field observations during ASP and subsequent polymer chase injection will be presented. The results of this work could be used to define the polymer specifications for ASP and polymer flooding in the reservoir with permeability range (from 10 to 100 mD) that is considered at the border of the typical screening criteria for the polymer application. Due to large amount of such reservoirs a successful mitigation for polymer injectivity could have significant impact on the application of polymer flood in the oil industry.


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