Summary. This paper describes the design, implementation, and initial results of the full-field water-injection program in the Ekofisk field of the North Sea. Two pilot waterfloods, injection-well-pattern design, verticalconfinement considerations, optimization of production-well sidetracks, corefracture analysis and orientation, production-well sidetracks, core fractureanalysis and orientation, regional per-meability variations, reservoir geologyand faulting, and overall anisotropy are discussed. Results of a comprehensive waterflood surv-eillance program are presented as well as 3D-model predictionsfor ultimate recoveries. Introduction The Ekofisk field is located in the Norwegian sector of the North Sea and iscomposed of two naturally fractured chalk formations, the Ekofisk and the Tor. This essentially volumetric, solution-gas-drive reservoir was initially undersaturated, with an initial pressure of 7,120 psi and a bubblepoint pressure of 5,545 psi at 268 degrees F. Initial psi and a bubblepoint pressureof 5,545 psi at 268 degrees F. Initial solution GOR at producing separatorconditions was 1,530 scf/STB, and initial oil gravity was 33 degrees API. Production started from four subsea producers in 1971 and switched to three permanent production platforms in 1975. Natural-gas injection (basically swinggas) was platforms in 1975. Natural-gas injection (basically swing gas) wasimplemented in 1975 and is expected to continue through 2011. This natural-gasinjection along with oil expansion, solution gas, gravity drainage, andcompaction drive would have yielded primary recoveries of about 24% in terms ofoil equivalent, primary recoveries of about 24% in terms of oil equivalent, assuming 6 Mcf = 1 bbl oil. The Ekofisk field waterflood was designed to enhance recovery from anaturally fractured, low matrix permeability, solution-gas-drive, chalkreservoir, which contained more than 6.8 × 109 bbl original oil in place(OOIP). Enhanced recovery potential from waterflooding was investigated through extensive laboratory experiments and pilot waterfloods to examine recoveries byspontaneous imbibition. A Tor formation pilots began in April 1981 andcontinued through June 1984. The results basically confirmed the laboratory results and were used to justify the field waterflood in the Tor formation. Approval to proceed with the Tor waterflood was granted in Oct. 1983, affectingthe northern two-thirds of the field. An additional platform (Platform 2/4 K)was constructed for the injection facilities and included well slots for 30wells. The total cost for the waterflood development was $1.5 billion. Fieldwater-flood injection began in Nov. 1987. A pilot in the lower Ekofisk formation began in June 1986 and continues todate. This pilot has performed beyond expectations and has supported the higherrange of laboratory measurements of spontaneous imbibition. The success of thispilot coupled with the early results of the Tor waterflood led to approval ofthe Ekofisk waterflood expansion project in June 1988. This project includedexpansion of water injection into the lower Ekofisk formation and the remaining Tor formation in the southern one-third of the field. It also included acomprehensive infill-drilling program. The initial Tor waterflood was expected to increase reserves from Ekofiskfield by 160 X 106 bbl oil equivalent. The waterflood expansion project isexpected to increase reserves by an additional project is expected to increasereserves by an additional I go X 106 bbl oil equivalent. In addition toincreased recovery, the waterflood became important in providing pressuresupport to help mitigate the reservoir subsidence identified in 1984. This paper describes the design, implementation, and monitoring program ofthe Ekofisk field waterflood. Pilot performance is compared to program of the Ekofisk field waterflood. Pilot performance is compared to an extensivedata-acquisition program, structured to solve critical unknowns in thewaterflood regions. Response curves are presented, and the experience gained inthe waterflood project is summarized. Reservoir Description Geology Overview. The two oil-producing formations in Ekofisk field, Ekofiskand Tor, are composed of chalk sediments made up mostly of skeletal carbonatematerial. The Ekofisk formation can be split into three layers: the upper andlower sections and the "tight zone" . The upper section containsalternating sequences of autochthonous deposition and reworked Danian-agematerial and has an average thickness of 400 ft. This section containsporosities of 25 to 48 % and moderate natural fracturing. The lower Ekofiskformation is primarily reworked Maastrichtian-age sediments of 120 ft averagethickness. primarily reworked Maastrichtian-age sediments of 120 ft averagethickness. The lower section contains uniform porosity in excess of 30% andintense natural fracturing, The tight zone is composed of an average of 70 ftof autochthonous chalk. This layer is characterized by low porosity andpermeability and restricts communication between the Ekofisk and Torpermeability and restricts communication between the Ekofisk and Tor formationsin the majority of the field. The Tor formation contains Maastrichtian-agereworked chalk sediments. Porosities between 25 and 40 % are typical, withoil-bearing sections up to 500 ft in the crestal region . Natural Fracture Description and Trends. Four major fracture types exist in Ekofisk: tectonic, stylolite-associated, irregular, and healed. Tectonicfractures predominate in the Ekofisk formation, while most of the fractures inthe Tor formation are stylolite-associated. The tectonic fractures in the Ekofisk form well-developed parallel andconjugate sets. The highly fractured zones typically have spacings as small as 2 to 6 in. Zones of lower fracture intensity have spacings of 6 to 40 in., with40-in. spacings rarely encountered. The dip of the tectonic fractures variesfrom 65 to 80 degrees. Stylolites in the Tor formation are parallel to beddingplanes and are usually only a few feet apart. Stylolite-associated fracturesdevelop perpendicular to the stylolite seams and are essentially vertical. Fracture lengths vary from 4 to 8 in. These fractures form permeable zonesparallel to bedding planes that extend laterally for large distances. The mosthighly fractured zones correspond to areas with the greatest rate of change instructured dip. Two major fracture trends exist in Ekofisk field. The dominant trend in themajority of the field is a basement-faulting-dominated, north-northeast/south-southwest trend. This trend is especially pronounced inthe north and northwest portions of the field and is largely responsible forthe prolific nature of these regions. A secondary radial trend resulting fromstructural uplift is present throughout the field and is related to the rate ofchange in structural dip. This fracture trend becomes most important in regionsor the field where the basement-dominated trend becomes less pronounced. Theseareas demonstrate overall lower fracture intensities, and pronounced. Theseareas demonstrate overall lower fracture intensities, and thus lowerproductivity, and are commonly encountered in the eastern and southernflanks. Effective permeabilities have been calculated from well tests up to a factor of 50 times the 1 - to 2-md matrix values. These permeabilities have beenobserved in the most intensely fractured regions permeabilities have beenobserved in the most intensely fractured regions of both formations and aredirectly related to the fracture intensity. Fig. 1 depicts the importance ofnatural fracturing to well productivity in a typical log section of an Ekofiskwell. SPEFE P. 284
This paper documents the design, operation, analysis and use of two different radioactive tracers, tritium and iodide-125, which were injected in the Ekofisk Formation Pilot Waterflood Project. This paper also describes how Pilot Waterflood Project. This paper also describes how chemical analysis of water produced in the offset producers during the pilot project was successfully analyzed, interpreted, and used as a second tracer method. Both tracer methods were used to evaluate waterflood mechanisms and were invaluable to the overall interpretation of the Ekofisk Formation Pilot. A comparison of both methods is made to demonstrate their repeatability for possible future use. possible future use. During the pilot water injection program, clear responses from the injected radioactive tracers were identified from the three production wells within the pilot. Analysis of the produced water from these wells was carried out in the laboratories of IFE ("Institutt for Energiteknikk") in Oslo with an accuracy within 1–2 percent. Chemical composition of the produced water was monitored during the same tracer injection period which showed a direct correlation. The large differences in sulfate concentration between Ekofisk formation water and the injected seawater makes this ion a good alternative to the more ideal radioactive tritium tracer. Careful analysis of the various tracers in the Ekofisk Formation Pilot confirmed that both waterflood recovery mechanisms capillary imbibition and viscous displacement were contributing to the overall waterflood recovery. This was a key element in the interpretation and simulation of the pilot. Introduction The Ekofisk Field is located in the Norwegian Sector of the North Sea and is composed of two naturally fractured chalk formations, the Ekofisk and the Tor. This essentially volumetric, solution gas drive reservoir was initially under-saturated, with an initial pressure of 7120 psi and a bubble point pressure of 5545 psi at 268 degrees Fahrenheit. Initial solution GOR at producing separator conditions was 1530 SCF/STB and initial oil gravity was 33 degrees API. Production from Ekofisk was commenced in 1971 through four Production from Ekofisk was commenced in 1971 through four subsea producers and switched to three permanent production platforms in 1975. Production peaked in 1976 at over platforms in 1975. Production peaked in 1976 at over 300,000 BOPD and declined to below 75,000 BOPD by mid 1986. Through waterflooding, the oil production has increased to the current level of 130,000 BOPD. Reservoir pressure declined through the bubble point pressure of 5545 psi in 1978 after which producing GOR from the field increased and peaked at 9000 SCF/STB in 1986. Through 1989, Ekofisk had peaked at 9000 SCF/STB in 1986. Through 1989, Ekofisk had produced 1,362 million barrels of oil equivalents. produced 1,362 million barrels of oil equivalents. Waterflooding was first initiated in Ekofisk Field in November 1987 and was restricted to the Tor formation in the northern two thirds of the field. This was preceded by extensive study of laboratory imbibition experiments and a pilot waterflood project to confirm laboratory results and to gain experience from water injection into the highly fractured chalks. Initial laboratory data had indicated water injection into the Ekofisk formation was of lower potential. in June 1986 a Lower Ekofisk Formation Pilot was initiated to determine waterflooding potential of that formation. The pilot was configured similar to the Tor Pilot 1 with injection through Well B-16 situated in the middle of a triangle formed by the three producers Well B-19, Well B-22 and Well B-24 (Figure 1). P. 559
SPE Members I. Abstract This paper describes the design, operation and evaluation of a pilot waterflood project initiated in the Lower Ekofisk project initiated in the Lower Ekofisk Formation of the Ekofisk Field located in the Norwegian sector of the North Sea. Previously, a pilot waterflood project in Previously, a pilot waterflood project in the Tor Formation led to approval in 1983 of full scale water injection in the Tor Formation. The Ekofisk and Tor Formations are both low matrix permeability chalks characterized by intense natural fracturing. This natural fracturing has enhanced overall permeability and made commercial production permeability and made commercial production possible from these volumetric solution gas possible from these volumetric solution gas drive reservoirs. The Ekofisk Formation was initially given lower waterflood priority based on spontaneous imbibition laboratory experiments. However, the large values of initial oil in place, in combination with the recognition that mechanisms other than imbibition may play a role in waterflood performance necessitated a pilot be performance necessitated a pilot be performed. Additionally, the pilot was performed. Additionally, the pilot was designed to evaluate rock stability and injectivity in this fractured chalk reservoir. The pilot project consisted of one injector and three producers in an unconfined four spot pattern. As of May 1985, a total of 10 million barrels of water had been injected over a 22 month period. Results have been favorable and have been utilized to justify expansion of the waterflood to the Lower Ekofisk Formation. Factors which were taken into consideration during the analysis include lack of both vertical and horizontal confinement, significant initial gas saturation, influence of gas injection, regional permeability variations, anisotropy and layering effects. Three dimensional simulation results are included which tie all the parameters together and form the basis for parameters together and form the basis for extrapolating results to full field. II. Introduction The Ekofisk Field in the Norwegian Sector of the North Sea is an overpressured naturally fractured chalk reservoir. The 6.7 billion barrels of oil and 10.33 trillion cubic feet of gas, originally in place is split between the Ekofisk (Danian place is split between the Ekofisk (Danian Age) Formation with 2/3 and the Tor (Maastrichtian Age) Formation with 1/3. Production is from three platforms, 2/4 A Production is from three platforms, 2/4 A in the south, 2/4 B in the north and 2/4 C in the center of the field. Recovery by primary depletion is estimated at 24% of primary depletion is estimated at 24% of oil equivalents. The large initial oil in place in combination with low recovery place in combination with low recovery factors necessitated enhanced oil recovery projects be given highest priority. projects be given highest priority. Initial laboratory imbibition experiments indicated a favorable waterflood potential in the Tor Formation, with a poorer recovery potential in the Ekofisk Formation. A Tor Formation pilot waterflood was performed in Ekofisk Field from April 1951 to June 1984 to evaluate in-situ waterflood performance. The results were favorable and used to justify a full field waterflood of that formation. The 30-slot water injection platform 2/4 K was approved to develop an estimated 162 MMBOE reserves utilizing 20 of the available slots to waterflood the northern two thirds of the Tor Formation. P. 153
The South Cowden (San Andres) Unit is the site selected for one of three mid-term projects to be conducted under the DOE Class II Oil Program for Shallow Shelf Carbonate Reservoirs. The proposed $21 million dollar project is designed to demonstrate the technical and economic viability of an innovative CO2 flood project development approach. The new approach employs cost-effective advanced reservoir characterization technology as an integral part of a focused development plan utilizing horizontal CO2 injection wells and centralization of production/injection facilities to optimize CO2 project economics. If proven successful, this new approach will help improve the economic viability of CO2 flooding for many older, smaller fields which are or soon will be facing abandonment. Introduction CO2 miscible flooding has been demonstrated to be a technically viable tertiary enhanced oil recovery process which can extend the producing life and add significantly to the ultimate recovery of the remaining oil resource in Shallow Shelf Carbonate reservoirs in the Permian Basin. Most of the incremental tertiary oil production from CO2 projects implemented to date has come from a few, large scale projects where the sizable economies of scale inherent in this type of development improve project economics. In 1992, Moritis reported that the five largest CO2 projects accounted for over one-half of the total incremental oil production attributable to CO2 miscible flooding in the United States. Lang, et. al. estimate that between 250 and 575 million barrels of incremental oil could be produced from new CO2 miscible flood projects in the Permian Basin over the next 25 years if oil prices stabilize in the $16 to $20 per barrel range. P. 409^
The purpose of this project was to economically design an optimum carbon dioxide (CQ) flood for a mature waterflood nearing its economic abandonment. The original project utilized advanced reservoir characterization and C 0 2 horizontal injection wells as the primary methods to redevelop the South Cowden Unit (SCU). The development plans; project implementation and reservoir management techniques were to be transferred to the public domain to assist in preventing premature abandonment of similar fields. The Unit was a mature waterflood with water cut exceeding 95%. Oil must be mobilized through the use of a miscible or near-miscible fluid to recover significant additional reserves. Also, because the unit was relatively small, it did not have the benefit of economies of scale inherent in normal larger scale projects. Thus, new and innovative methods were required to reduce investment and operating costs. Two primary methods used to accomplish improved economics were use of reservoir characterization to restrict the flood to the higher quality rock in the unit and use of horizontal injection wells to cut investment and operating costs. The project consisted of two budget phases. Budget Phase I started in June 1994 and ended late June 1996. In this phase Reservoir Analysis, Characterization Tasks and Advanced Technology Definition Tasks were completed. Completion enabled the project to be designed, evaluated, and an Authority for Expenditure (AFE) for project implementation submitted to working interest owners for approval. Budget Phase I1 consisted of the implementation and execution of the project in the field. Phase I1 was completed in July 2001. Performance monitoring, during Phase 11, by mid 1998 identified the majority of producing wells which under performed their anticipated withdrawal rates. Newly drilled and reactivated wells had lower offfake rates than originally forecasted. As a result of poor offfake, higher reservoir pressure was a concern for the project as it limited C02 injectivity. To reduce voidage balance, and reservoir pressure, a disposal well was therefore drilled. Several injection surveys indicated the C02 injection wells had severe conformance issues. After close monitoring of the project to the end of 1999, it was evident the project would not recover the anticipated tertiary reserves. The main reasons for under-performance were poor in zone CO2 injection into the upper San Andres layers, poorer offtake rates from newly drilled replacement wells and a higher than required reservoir pressure. After discussion internally within Phillips, externally with the Department of Energy (DOE) and SCU partners, a redevelopment of South Cowden was agreed upon to commence in year 2000. The redevelopment essentially abandoned the original development for Budget Phase I1 in favor of a revised approach. This involved conformance techniques to resolve out of zone CQ injection and use of horizontal wells to improve in zone injectivity and productivity. V Phase 2 activities commenced in October 2000 w i t h ...
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