Field-Related Mathematical Model To Predict and Reduce Reservoir Souring

Abstract

Field-Related Mathematical Model To Predict and Reduce Reservoir Souring Egil Sunde; Egil Sunde Statoil A/S Search for other works by this author on: This Site Google Scholar Tore Thorstenson; Tore Thorstenson Statoil A/S Search for other works by this author on: This Site Google Scholar Terje Torsvik; Terje Torsvik U. of Bergen Search for other works by this author on: This Site Google Scholar J.E. Vaag; J.E. Vaag U. of Bergen Search for other works by this author on: This Site Google Scholar M.S. Espedal M.S. Espedal U. of Bergen Search for other works by this author on: This Site Google Scholar Paper presented at the SPE International Symposium on Oilfield Chemistry, New Orleans, Louisiana, March 1993. Paper Number: SPE-25197-MS https://doi.org/10.2118/25197-MS Published: March 02 1993 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Sunde, Egil, Thorstenson, Tore, Torsvik, Terje, Vaag, J.E., and M.S. Espedal. "Field-Related Mathematical Model To Predict and Reduce Reservoir Souring." Paper presented at the SPE International Symposium on Oilfield Chemistry, New Orleans, Louisiana, March 1993. doi: https://doi.org/10.2118/25197-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE International Conference on Oilfield Chemistry Search Advanced Search ABSTRACT.A mathematical model for reservoir souring caused by growth of sulfate reducing bacteria (SRB) in the reservoir has been developed. The model is a 1D numerical transport model based on conservation equations and includes bacterial growth rates, the effect of nutrients, water mixing, transport and adsorption of H2S in the reservoir formation.Two basic concepts for microbial H2S production were tested using the model: H2S production in the mixing zone between formation water and injection water (mixing zone model), and HS production due to SRB growth in a biofilm in the reservoir rock close to the injection well (biofilm model). In both cases H2S adsorption by reservoir rock was considered.Field data obtained from three oil producing wells on the Gullfaks field correlated with H2S production profiles obtained using the biofilm model, but could not be explained by the mixing model.The biofilm model implies that H2S production is correlated to the quality of the injection water, especially nitrogen (N) and phosphorous (P). The use of chemicals (containing N and P) in injection water treatment should therefore be reduced to a minimum.IntroductionInjection of seawater into oil reservoirs for secondary recovery has, on many oil fields, resulted in reservoir souring. Several causes for this souring have been debated (ref. 1, 2), but there is now a general consensus that growth of sulfate reducing bacteria (SRB) is the major source of increased H2S concentration in reservoir fluids (ref. 3, 4 and 5).Knowing that SRB are responsible for reservoir souring has, however, not answered the important questions of how to predict and minimize H2S production, but fundamental information is now available on which to build models.Even though there is good knowledge about nutrient requirements and the physical/chemical environment suitable for SRB growth, so far too little has been known about this process in relation to seawater moving from injector to producer. There has been a widespread opinion that the bacteria follow the injection water when the permeability exceeds 100 mD (ref. 6). This water will mix with the formation water resulting in a gradually increasing mixing zone which apparently contains suitable growth conditions for SRB. The resulting H2S production profile should therefore be a peak short after seawater breakthrough and thereafter a decline.This is not, however, the case. Normally souring starts after several pore volumes of injection water have been produced. It starts with a sudden increase in H2S followed by a more or less steady increase for a longer period of time.There may be several explanations for this phenomenon and this paper will elaborate on a possible mechanism and present a mathematical model and field data that support the theory.FUNDAMENTALS OF THE SOURING MODELIn all bacterial systems there is a limiting factor for growth which can be lack of nutrients, a physical constraint or the presence of inhibitory factors. Given the facts that seawater is an excellent medium for bacterial growth with regards to salinity, pH and redox potential and that bacteria grow well under the temperatures and pressures encountered in souring fields, the following model considers lack of nutrients to be the limiting factor for bacterial growth.p.449 Keywords: biofilm model, injection water, seawater breakthrough, production profile, reservoir souring, society of petroleum engineers, souring, formation water, bacteria, srb Subjects: Production Chemistry, Metallurgy and Biology, Improved and Enhanced Recovery, Health, Waterflooding, Noise, chemicals, and other workplace hazards, Corrosion inhibition and management (including H2S and CO2) This content is only available via PDF. 1993. Society of Petroleum Engineers You can access this article if you purchase or spend a download.