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'This paper presents a screening study for the application of chemical EOR methods of polymer, surfactant polymer (SP) and alkaline surfactant polymer (ASP) in Chicontepec fields through mechanistically-based simulations using the UTCHEM simulator. A finely-characterized 20 acre five-spot sector model within the lower sands of the Agua Fria field is considered, and numerous chemical flooding sensitivity simulations are conducted based on laboratory data available for similar crude oil and formation properties of Chicontepec oil field. Design parameters such as surfactant and polymer concentrations, surfactant slug size, polymer drive size and concentration, salinity of the polymer drive, polymer and surfactant adsorptions are the sensitivity parameters. Injectivity of these chemical EOR agents is also investigated to assess the operational and economic viability of such EOR projects. The simulations show average incremental oil recovery factor (over waterflood) of about 5%, 18% and 24% OOIP for polymer, SP and ASP; respectively. These incremental recovery figures are slightly lower than the expected results in other fields in the world with moderate reservoir permeability ranges, but still quite attractive for the low permeability Chicontepec field, given the typical performance and consumption of the chemicals. Thus, attractive incremental oil recoveries are possible and hence there is potential for chemical EOR in Chiontepec.

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'This paper presents an investigation of ranges of uncertainty in the oil recovery by water, CO2 and CO2-WAG injections into an inverted 7-spot pilot simulation model in a lower sand body of the Tajin field of Chicontepec. First, 50 integrated geostatistical reservoir characterization realizations are ranked based on a pay-sand connectivity between all well pairs in the sector model. The criterion for the connectivity is discussed. Second, 10 geostatistical realizations, covering worst to best connectivity (i.e., reservoir rock quality ranging from poor to good) are selected for flow simulations and assessment of oil recovery factor for uncertainty evaluation. Each of the selected models is upscaled for compositional flow simulations and calibrated to dynamic production data. Water, CO2 and CO2-WAG are injected into the 10 calibrated models for 15 years, and ranges of uncertainty in recovery factors are subsequently captured. The results show that CO2-EOR processes recover 7-10% additional oil compared to waterfloods for the same reservoir characteristics. Consistently higher incremental recovery factors by CO2-EOR for varied reservoir heterogeneity signify the economic value of CO2 injection for field development.

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'This paper presents results of a simulation study to investigate the feasibility of using foam and EOR surfactants to recover the gas-cap oil from the naturally fractured Akal reservoir. Foam-assisted EOR targets the bypassed oil in the tight matrix as the gas cap in Akal expanded. Foam reduces mobility within the fracture network and diverts the injected chemical surfactant solution to the tight matrix, which can either alter the oil-wet wettability characteristics of the matrix and/or reduce the IFT between the oil and water for subsequent release and mobilization of matrix oil. A single well r-z simulation model targeted a small interval of about 25 m in the gas cap as a potential pilot test site to evaluate the performance of various fluid injection scenarios of foamed N2 with chemical surfactants to enhance gravity drainage and recover the gas-cap oil. A combination of immiscible gas drive, rock wettability alteration and IFT reduction through the placement of chemical surfactant solutions within matrix is shown to promote gravity drainage and assist in the gas-cap oil recovery. Sensitivity studies on the effect of foam strength and the extent of wettability alteration demonstrate that the efficiency of gas-cap oil recovery increases for stronger foams that have higher ability to divert flow to within matrix.

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