A Mechanistic Model To Evaluate Reservoir Souring in the Ekofisk Field
Authors: Burger E.D. , Jenneman G.E. , Bache Ø. , Jensen T.B. , Soerensen S. 
Published: December 2007

Abstract
This paper presents a mechanistic approach to modeling the reservoir souring process in the Ekofisk Field, located in the Norwegian sector of the North Sea with over 6 billion STB OOIP and currently producing about 300,000 BOPD and injecting around 500,000 BWPD sea water. The objectives of this study were to determine if observed increases in H2S concentrations from this seawater-flooded oilfield were due to microbiological activity and, if so, to estimate future H2S production with further seawater injection and proposed produced water reinjection. Mechanisms considered in the model were imbibition and water flow through a highly fractured chalk formation; generation of H2S due to the activity of sulfate-reducing bacteria (SRB); and partitioning of H2S between the oil, water, and gas within the reservoir and in the topside separation system.
Model-calculated H2S production rates for individual wells, waterflood patterns, and full-field compared well to actual rates. Results indicated that both the water-oil and gas-oil ratios have a large impact on measured H2S concentrations in the produced gas, but that increased water production is responsible for significant increases in total H2S production. However, results also indicated that only a small fraction of the biogenic H2S will be transported to the producer.
This model presents a new approach for evaluating and forecasting the effects of souring for a naturally fractured reservoir whereby a biofilm is developed on the fracture faces and microbial nutrients are provided by incoming seawater and from formation water initially in the chalk matrix. It incorporates a mechanistic understanding of all of the key processes and is calibrated using the actual historical production rates from wells in several waterflood patterns. Presented in this paper are the model-forecasted results for the field-wide H2S production associated with continued seawater injection.

Introduction
The Ekofisk Field, discovered in 1969, is located in the far southwest corner of the Norwegian Sector of the North Sea.1 The reservoir is an elongated anticline comprised of naturally fractured chalk that produces from two major formations: Ekofisk and Tor. The overlying Ekofisk Formation is 9600 feet deep and varies in thickness from 350 to 500 feet while the Tor Formation varies in thickness from 250 to 500 feet. Porosities for the two formations range between 30 and 48% with a matrix permeability of 1 to 3 mD. The initial reservoir temperature was 131°C. Estimates place OOIP at 6.4 billion STB and GIIP at 10.3 trillion scf with an ultimate waterflood recovery factor of 38%.2 At peak production in 1976 Ekofisk produced over 350,000 STB/D of 38° API gravity oil.
A waterflood (375,000 BWPD unheated sea water capacity) was implemented in 1987 in the northern half of the field.3 The success of this waterflood prompted its field-wide expansion over the next several years to a capacity of 830,000 BWPD.Seawater is fine filtered, continuously disinfected with ultraviolet light, deaerated, and batch treated with biocide prior to injection.4 Breakthrough of seawater occurred in several Ekofisk wells as early as 1994.Current production from the PL018 license area that includes the Ekofisk, Eldfisk, Embla, and Tor Fields is approximately 365,000 STB/D and 140,000 BWPD with peak production of water expected to reach about 260,000 BWPD by 2012. The produced water is separated from the oil and gas at five different offshore installations and then cleaned to provide oil-in-water concentrations below 40 ppm before being discharged to the North Sea. The final separation of oil, water, and gas is performed on the centralized J Platform.