Ekofisk Field Enhanced Recovery
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Cited by 4 publications
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The impact of brine salinity and its ionic composition on oil recovery on chalk formations and to less extent in carbonate reservoirs have been investigated extensively in recent years due to the potential of extra oil recovery. Surface wettability was suggested to be the main reason behind such extra recovery. This study investigates the wettability alteration of calcite crystal and carbonates outcrop rock surface aged in model oils of total acid number of 2 and then treated with different brines. Model oils were prepared by mixing toluene with short chain (Heptanoic acid) and long chain (Stearic acid) carboxylic acids and the investigated brines included range of salinity and the effect of individual ions such as SO42−, Ca2+ and Mg2+. The results of this study showed that the long chain fatty acid (stearic acid) strongly adsorbs onto the calcite surface from the oil phase compared to the short chain (heptanoic acid) as confirmed by the measured contact angles. Twice dilution of Arabian Gulf seawater has been found to be a less effecient EOR fluid for wettability alteration as compared to undiluted Arabian Gulf seawater. This was confirmed by the changes in the measured contact angles toward more water-wet for aged calcite in heptanoic acid model oil, aged calcite in stearic acid model oil and aged carbonate in stearic acid model oil systems. Also, it was observed that significant wettability alteration was observed for the twice diluted Arabian Gulf seawater with higher concentrations of SO42− and Mg2+.
The impact of brine salinity and its ionic composition on oil recovery on chalk formations and to less extent in carbonate reservoirs have been investigated extensively in recent years due to the potential of extra oil recovery. Surface wettability was suggested to be the main reason behind such extra recovery. This study investigates the wettability alteration of calcite crystal and carbonates outcrop rock surface aged in model oils of total acid number of 2 and then treated with different brines. Model oils were prepared by mixing toluene with short chain (Heptanoic acid) and long chain (Stearic acid) carboxylic acids and the investigated brines included range of salinity and the effect of individual ions such as SO42−, Ca2+ and Mg2+. The results of this study showed that the long chain fatty acid (stearic acid) strongly adsorbs onto the calcite surface from the oil phase compared to the short chain (heptanoic acid) as confirmed by the measured contact angles. Twice dilution of Arabian Gulf seawater has been found to be a less effecient EOR fluid for wettability alteration as compared to undiluted Arabian Gulf seawater. This was confirmed by the changes in the measured contact angles toward more water-wet for aged calcite in heptanoic acid model oil, aged calcite in stearic acid model oil and aged carbonate in stearic acid model oil systems. Also, it was observed that significant wettability alteration was observed for the twice diluted Arabian Gulf seawater with higher concentrations of SO42− and Mg2+.
Pore pressure drawdown during reservoir depletion results in reduced horizontal principal stresses within a reservoir due to three distinct mechanisms: normal compaction, poroelastic behaviour and normal faulting. Established relationships, based on simplifying assumptions, give the ratio of the change in minimum horizontal stress, S h , to the change in pore pressure, P , in terms of sediment properties for each mechanism. In spite of the approximations introduced by the assumptions, these relationships may be useful for discriminating between the mechanisms that control the reservoir stress path. For the Norwegian chalk oilfields, it is important to know whether normal faulting, in particular, is the governing mechanism because slip on active faults can shear well casings, and active faulting and fracturing can increase reservoir permeability. Previously reported field observations and laboratory measurements on chalk samples are compared to infer the mechanisms governing the reservoir stress path for the Ekofisk and Valhall fields. The amount of subsidence at the seabed observed at Ekofisk is evidence that the weaker horizons within the reservoirs are yielding plastically through pore collapse. Nevertheless, the reservoir stress path corresponds to that expected for poroelastic behaviour or normal faulting, and not that expected for plastic yielding.
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
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