The concept of steamflooding the Wafra Eocene dolomite reservoir originated in various studies conducted in the 1980's. In 1999, a comprehensive EOR study and Eocene huff-n-puff pilot suggested that steamflooding could be a viable recovery process for the reservoir. As a result of these studies, a staged development approach was incorporated to test the viability of pattern steamflooding the Eocene reservoir. The objective was to assess key technical challenges associated with steamflooding an anhydrite and gypsum rich carbonate reservoir. Additional challenges were the lack of fresh water available for steam generation, high concentrations of hydrogen sulfide gas, and higher reservoir pressures compared to most active steamfloods. The staged approach called for a single pattern steamflood test followed by a larger multi-pattern pilot. As a result of this strategy, a single pattern steamflood test was implemented in 2006. The design and initial performance of the small scale test (SST) single pattern steamflood pilot in the Wafra 1st Eocene reservoir are described in this paper. The pilot is comprised of one, 1.25 acre inverted five-spot pattern, consisting of four producing wells, a single injector and a single observation well. Continuous steam injection began in February 2006 at a rate of approximately 500 barrels per day cold water equivalent, 600 psig and a temperature of 489 ºF. The primary goals of the single pattern test were to test application of a mechanical seeded slurry evaporator to process produced water for steam generation and to assess steam injectivity into dolomite reservoirs containing gypsum and/or anhydrite. Injectivity assessment included evaluating reservoir response to steamflooding and investigating the variation over time due to rock/fluid interactions. Secondary objectives included analyzing well productivity and evaluating well testing equipment, facilities, and well construction. The SST has a comprehensive data collection and surveillance plan to support evaluation of these goals and objectives. The surveillance plan includes the collection of pre-flood and post-flood core data, frequent well testing for rates and fluid compositions, daily temperature recordings and periodic logging. After two years of operation, primary goals have been tested and exceeded expectations. A continuous thermal zone was developed in the 1st Eocene reservoir and steam breakthrough occurred at several of the producers. Generator feed quality water was produced at maximum throughput rate of 1,200 bwpd via mechanical seeded slurry evaporator equipment. Secondary objectives are currently being assessed with focus on current challenges of corrosion and scaling of producing wells.

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The Ku, Maloob and Zaap (KMZ) complex is located offshore in the shallow waters of the Gulf of Mexico, in the bay of Campeche, 105 kilometers from Ciudad del Carmen. The complex oil production averaged 850,000 BOPD in 2012. KMZ has been Mexico's largest contributor to production since January 2009. The fluid is heavy oil of 22°API in Ku, and 13°API in Maloob-Zaap. The Cretaceous is the main producing formation. This carbonate reservoir is a naturally fractured dolomite that also contains matrix and vuggy porosity. Average permeability and gross thickness are 4,000 md and 700 m, respectively.Field production began in 1981. More than 150 wells were active in 2012. The initial reservoir pressure of 4,594 psi declined to about 1,707 psi as of 2012. Nitrogen injection began in 2009 for pressure maintenance.Reservoir simulation has been used in the KMZ complex during the last 15 years to support key reservoir management decisions. The Cretaceous reservoir was simulated as a dual porosity/single permeability system. The different fluids of Ku and Maloob-Zaap were each represented by a 6-component equation of state. The simulation was implemented as compositional to model the nitrogen injection. The aquifer volume was represented by applying pore volume multipliers to grid cells. One set of gas-oil and water-oil relative permeability and capillary pressure was assigned to the whole reservoir, along with one pressure dependent pore volume compressibility. Simple input parameters were used whenever possible for the history match.The simulation model matched the historical pressure and the production of oil, water, and gas by field satisfactorily. The match by well was fit-for-purpose. The production/injection forecasts helped support reserves, the complex plateau rate, the pressure maintenance strategy, the development scenario, and the timing and capacity of future facilities needed to manage increasing water production. This case study shows that even though reservoir simulation has limitations as any other tool, it is excellent for validating reservoir mechanisms and serving as the basis for estimating field long-term production performance, and providing support for economic and financial decisions.