This paper describes field and laboratory work carried out recently to better understand stimulation behavior in Ekofisk Area North Sea chalks. Laboratory work has been done to study chalk hardness, chalk mechanical properties, and the development and stability of propped and acid fracture conductivity. The laboratory work, combined with a review of available stimulation techniques for these formations, shows that stimulations in most of these reservoirs can be optimized with a pseudo limited entry acid fracture technique. Cased hole logging, pressure transient tests, and other field data have been utilized to optimize the design of these stimulations. The best treatments have resulted when several widely spaced clusters of perforations are treated in stages using ball sealers for diversion. Introduction The Greater Ekofisk Area (GEA) chalk fields are located in the Norwegian Sector of the North Sea (Figure 1), in 250 feet of water 180 miles Southwest of Stavanger,, Norway and comprise four oil fields (Edda, Ekofisk, Eldfisk, and Tor) and two gas condensate reservoirs (Albuskjell and West Ekofisk). The discovery well in the area was drilled on the Ekofisk structure in 1969. The Ekofisk field was the first giant oil field discovered in Western Europe and the first to produce significantly from a North Sea chalk formation. Cumulative production through 1987 from the six fields was 1.43 BSTB of oil and 5.5 TSCF of gas. Ultimate recovery is estimated to be 2.5 BSTB and 8.6 TSCF. Since the Ekofisk discovery, several studies related to North sea chalk completions have been published. The most extensive study was a five year EEC sponsored project conducted by Shell. A North Sea chalk research group sponsored a similar study by Elf. In addition to these essentially theoretical studies, Amoco has published their work on the Valhall and Hod fields, which are located slightly south of the Ekofisk fields. In general, these studies have indicated that these formations are difficult stimulation targets for any of the following reasons:The massive, uniform nature of the chalk sections result in short, radial fracturegrowth.The low hardness and ductile behavior of the chalk results in pore collapse and creep causing excessive proppant embedment.The homogeneous nature of the chalk results in evenly etched fracture faces during acid fracture stimulation.The low hardness and low yield strength of the chalk can lead to healing of natural fractures and failure of any acid-etched grooves.The chalks lose mechanical strength when contacted by foreign fluids, causing stimulation with water based fluids to actually damage, and not stimulate, the formation. Very little actual field data related to North Sea chalk stimulation has been presented in the literature. This paper reports some of the field and laboratory experience which Phillips has had with the Ekofisk Area chalks.

This paper describes pressure transient testing and analysis procedures used in the Ekofisk Area chalk fields. These chalks consist of low permeability, thick, naturally fractured formations which are stimulated by pseudo limited entry, massive acid fracturing. Transient tests are interpreted in real time utilizing an on site portable computer. Test interpretation requires the use of spinner and/or separator rates for normalization, superpositioning, and pressure derivative data. The, induced pressure derivative data. The, induced fracture systems are complex, having multiple fractures which are partially penetrating with limited perforation penetrating with limited perforation height and other non-ideal characteristics. It has not been possible to isolate the character of these nonideal conditions through pressure transient analysis. instead, an equivalent fracture system which behaves similar to the actual system is identified during the test interpretation. Using the equivalent fracture system concept, it has been possible to accurately forecast possible to accurately forecast production, monitor well performance, production, monitor well performance, evaluate the need for restimulation, and optimize completion and stimulation designs. Introduction The Ekofisk Area chalk fields, operated by Philips Petroleum Company Norway, comprise six fields in the southern part of the Norwegian Sector of the North Sea. They include two gas condensate (Albuskjell and West Ekofisk) and four volatile oil fields (Edda, Ekofisk, Eldfisk, and Tor) (Figure 1). The Ekofisk field was discovered in 1969 and was the first major oil field discovered in the North Sea. To date the fields have produced 1.43 BSTB of oil and 5.5 TSCF of produced 1.43 BSTB of oil and 5.5 TSCF of gas. The Ekofisk Area fields produce from chalks of Danian and Maastrichtian Age. These chalks are naturally fractured, with the natural fracture intensity varying from slight to high. All wells are stimulated with pseudo limited entry, massive acid treatments. In most cases these stimulations result in the formation of multiple hydraulic fractures, although in some cases the wells are only matrix acidized. Theoretical studies have been published on transient testing in both non-stimulated and stimulated, naturally fractured wells as well as on the interpretation of transient tests for wells that have been acid fractured. Novtony studied acid fractured wells and found that they exhibit finite conductivity behavior. McDonald reviewed pressure tests from wells which had been pressure tests from wells which had been stimulated by massive acid fracturing. The wells that he reviewed exhibited infinite fracture conductivity and the fracture lengths corresponded closely to a radial fracture growth model. Gringarten, et al. proposed that acid fractured wells exhibited uniform flux conductivity. Warren and Root studied pressure transient behavior of naturally pressure transient behavior of naturally fractured wells and found that pressure tests could exhibit two straight line regions: one representing natural fracture drainage. P. 37

SPE Members Abstract A major field study was conducted to determine future operating strategy for Ekofisk Field. Historical and predicted performance of various IOR processes were evaluated and an IOR process was selected. The evaluation was made in the context of ongoing Upper Ekofisk Formation gas injection and water injection into the underlying Lower Ekofisk and Tor formations. Optimization of the recommended waterflood and studies of other reservoir management concerns are described. The reservoir management strategy was developed to integrate the most economical improved oil recovery process with a strategy to minimize future subsidence. Introduction Ekofisk Field is a mature oil field currently being waterflooded for improved recovery in the lower two thirds of the reservoir. Starting in 1991, a major field study was undertaken to determine the future operating strategy for the field. Historical performance and predictions for improved oil recovery (IOR) processes were evaluated and an IOR process selected. The evaluation considered ongoing hydrocarbon gas injection and pilot water injection in the Upper Ekofisk as well as ongoing water injection into the underlying Lower Ekofisk and Tor formations. In addition, optimization of field wide IOR processes was carried out to maximize recovery while managing sea floor subsidence. In late 1992, the results of the study were presented as an Extended Field Study (EFS) to the Norwegian Petroleum Directorate. Background Ekofisk Field is located in the Norwegian sector of the North Sea and currently produces approximately 150,000 BOPD and 680,000 MSCFD from 70 wells. Current water injection into the lower two thirds of the field is 500,000 BWPD into 35 wells. The structure is a large elliptical anticline, 6.6 miles long and 3.2 miles wide, with the top of the structure at 9500 feet sub-sea true vertical depth (TVD). Structural relief is significant only because of the size of the field; the angle of dip is very low, averaging less than 4 degrees. The reservoir varies from 300 to 1000 feet in thickness and can be subdivided into 3 major geologic zones: the Upper Ekofisk, Lower Ekofisk and Tor formations. The Tor Formation is composed of porous chalk of Maastrichtian (U. Cretaceous) Age. Overlying the Tor Formation is a low porosity impermeable zone which comprises the base of the Danian Age (Paleocene) Lower Ekofisk Formation. The remainder of the Lower Ekotisk Formation consists of reworked Cretaceous chalk and has similar reservoir characteristics to the Tor Formation. The Upper Ekofisk Formation was deposited in a lower energy environment and has generally lower porosity and permeability. Each of the major intervals contains approximately one third of the original oil in place. Ekofisk Field is a low permeability fractured chalk with matrix permeabilities ranging from 0.1 to 10 md. Effective permeabilities are 2 to 50 times the chalk matrix permeability. Vertical permeability ranges from 0.1 to less than 0.01 times that of the horizontal effective permeability. The chalk is a soft, low strength sediment with reservoir porosities ranging between 30% and 45%.

Where these models have been applied, they have Discoveryprocessmodels-we used to predictdrilling enhancedexploration/lease posit ion evaluation, basin successratesand field.>, ZPS for a developing basin." risk analysis evaluation,and alternativeenergyThe earliest attempts at these predictionsrelied supply determination.However,they have not found eitheron historical data (objective models)or on the generalapplication in the oil industry. development team's "feel" for the basin (subjective models ). Recentlymodels have been developedwhich This paper reviewsseveralof the models which have are more rigorousthan theseearliermodels. However, beendevelopedand indicates theirlimitations.A new thesemodelshave not foundgeneralusagebecausethey model is then developedbased on several of these 0149 are not applicable duringthe earlylife of the basin models vhich overcomes most of these and because they~re highly data intensive. A new limitations,It has been successfully appliedto both modelhas been developed which is basedon thesenewer a matureand an immaturshorizonin the GreaterGreen RiverBasin. modelsbut which is applicable duringthe entirelife Predictions have been made of the future of the ba~in and which is more flexiblein its data fielddiscoverysizes per incremental drillingeffort requireme,,~s. The model is appliedto both a mature in both horizons. and an immatu,'e horizon in the GreaterGreen River Basin. Definitions 3. How easilycan the questionsin (1) and (2) above 2. Energysource (primary, secon~'.try) be adjusted for changing ?, Economic(present cost lev,-l, specified cubt level, economic and/or technologicalclimates and as new information irrelevant cost level) becomesavailable. 4. Technological (currently feasible, indicated feasibility, infeasible -References and illustrations at end of paper.

Embla Field is located within the Greater Ekofisk Area in the Norwegian sector of the southern North Sea, 5 km south of the Eldfisk Field. A well drilled in 1974 indicated the presence of hydrocarbons. The producibility of the reservoir was proved by a well drilled in 1988. An appraisal well drilled in 1989 confirmed the discovery. During tests, the field produced volatile oil from a thick, pre-Jurassic sandstone sequence at about 4200 m lVD. Reservoir pressure is 828 bar and reservoir temperature is 15goC. A three phase development plan for the field was proposed and approved in 1990.Seismic definition of both the top of the reservoir and its internal geometry is poor. Log, core, and DST information indicate that the reservoir is geologically complex. In order to allow for geologic complexity, minimize economic risk and obtain the necessary information for optimum reservoir management, the first phase of the development will be a low cost wellhead platform which will take advantage of the existing infrastructure. Production from this phase will start in late 1992.Phase I will consist of pre-drilling up to 6 wells in a stepout fashion, installation of a remotely monitored 18 slot platform and one year of special reservoir monitoring from the pre-drilled wells. The reservoir monitoring program is designed to establish reservoir continuity and production characteristics. The information obtained References and illustrations at end of paper. 449 information obtained from the first phase will form the basis for the rest of the development.Phase II will include infill drilling and development of the remainder of the field. Phase 11\ will be a pressure maintenance/improved recovery program.Several alternative development schemes, including conventional delineation of the reservoir or test production through a subsea compietion, were considered. The selected alternative best addressed the uncertainties of Embla while taking advantage of the existing infrastructure.