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.

This p-r was "selected for presentation by an SPE Program Committee following review of informatiw wntained in an abstract submitted by the author(s). Contents of the pa~r, es ented, have not been reviewed by the Society of Petroleum Engineers and are subject to mien by the author(s). The material, aa prasantad, dws not nma.sarify Md anỹ~~o f the Society of Petroleum Enginaers, Rs Mmrs, w members Papers presentad at SPE meetings ars subjed to publimtion review by Edtiorial Ccfnmittees of the Society of Petrelaurn Engineers Elactronk r-ion, distrIMi, w storage of any parl d this pap.sr for rnmmemial purposes w~d the wittan ccilsent ef the .socie~of Petroleum Engineers is tiibiiad. Permission to reprodu~in print is restricted to an abstract of not more than 300 wurds; ilIustratMs may not be copied. The abatrad must contain mnepicuous lsdgment of whers and by whom the papr was presented, Writs Libratian, SPE, P.O Box =36, R&ardson, TX _3-=, U.S.A, fss 01-S72-952-e435. AbstractA comprehensive effort to estimate the range of uncetiainty in the long term forecast for the mature Ekofisk and surrounding fields (Eldtisk, Embla and Tor) located in the Norwegian sector of the North Sea is presented. Even for this mature production license (PLO18) which has been on production for more than 25 years we experience significant discrepancies between actual and forecasted production. This prompts the need for estimating the range of uncertainty in the reservoir production prognosis. Decision tree analysis formed the basis for our methodology in which each branch on the decision tree is coupled with a fill field 3D numerical reservoir model. A large number of fill fieId, numerical simulations were run to forecast the different reali=tions. Reservoir, operational and faciIity uncertainties were considered. These results were coupled with straightforward statistical techniques to allow estimation of probabilistic forecasts. Individual fields production forecasts were aggregated into a single license production forecast using Monte Carlo simulation.

This paper will review the history and current operations of the Kuparuk River Unit (KRU) field, the second largest field on the North Slope and one of the largest fields in the US. The field is a legacy asset in the ConocoPhillips portfolio with more than 6 BBO OOIP. The field came on line in December 1981 and has produced 2.25 BBO to date through water flood, immiscible water-alternating gas (IWAG) and miscible water-alternating-gas (MWAG) injections. Currently the field produces 90,000 bopd, 460,000 bwpd and 210 MMscf/d gas, and injects 570,000 bwpd and 160 MMscf/d miscible injectant. Some of the recent challenges at KRU include: maintaining pressure support (water injection) through an aging infrastructure, development and use of fit-for-purpose simulation models to support field management decisions, estimation of facilities back-out from a complex multi-field system, and optimization of one of the largest MWAG EOR floods in the world. History and current status of the KRU field will be discussed.

Published annular pressure drop field data have been compared with values predicted by the Bingham plastic and power law models. Several different equivalent diameter equations and friction factor correlations were utilized to estimate the frictional pressure gradients. The estimated frictional pressure drop gradients were then compared with the experimental gradients statistically to determine which combination of friction factor correlation and equivalent diameter equation predicted the experimental data best. Finally, new correlations for friction factors were developed. These new correlations predict the field data better than previously published correlations.

A mathematical model is proposed for analyzing the thermal hydraulic behavior of wellbores and surface lines. The model discusses two-phase pressure drop and heat transfer for a variety of practical wellbore boundary conditions and includes theoretical formulations for calculating effects of geothermal gradient, transient heat flow to the surroundings of the wellbore, and radiation and convection heat transfer in the annulus. The model has been applied to evaluate the effects of insulation thickness, injection rate and injection time on steam temperature and quality. Some interesting performance behaviors are noted. The predictions of the model are compared with the results of other models [1, 2] and a field case [29].