Naturally fractured carbonate reservoirs hold well over 100 billion barrels of heavy oil worldwide. Thermally Assisted Gas Oil Gravity Drainage (TAGOGD) is a new and novel thermal EOR technique, which has applicability in selected reservoirs. In conventional isothermal GOGD, vertical fractures cause the gas-oil contact in the fracture system to advance ahead of the gas-oil contact within the matrix blocks, causing the oil in these blocks to become mobile. The addition of heat in the fractures generates additional hydrocarbon gas cap, lowers the viscosity of the oil, and accelerates conventional GOGD, as seen in the 220 cp heavy-oil Qarn Alam field in Oman. Pilot results in the Qarn Alam field support the commerciality of this process, and a first-of-it's-kind steam injection project is being implemented. The economic success of the Qarn Alam project depends on the ability to credibly predict steam requirements and oil production. Two key oil production mechanisms are heat transport through the fractures and into the matrix, and subsequent gas cap generation due to thermal volatilization of the oil. The process mechanisms involved in TAGOGD were validated through laboratory experiments, while the field forecast model results were validated by history matching pilot performance data. A fully integrated workflow of fracture characterization, integrated reservoir physics, and static and dynamic modeling has enabled uncertainties and risks involved in developing the Qarn Alam field to be managed in a scenario based design approach. Introduction The Qarn Alam field is a highly fractured carbonate field that lies atop a salt diapir in Northern Oman. The 6 km long and 3 km wide field forms a relatively high-relief anticline with a N-NE by S-SW orientation. The reservoir is relatively compact dome-shaped structure, with a maximum oil column of 165 m. The main oil bearing reservoirs, the Shuaiba and Kharaib formations, are separated by a very low permeability oil bearing zone called the Hawar. The crest of the Shuaiba is located at 212 mss, and the original oil water contact is ∼375 mss. Fracturing occurs throughout all zones, and is believed to be contiguous and in hydraulic communication with a very active aquifer. The initial oil saturation is about 95% and initial water saturation is connate water. The matrix porosity is high (∼30%), while the matrix permeability ranges between 5 md-20 md. Under primary production, the reservoir produces on average about 100 m3/day of 16o API "heavy" oil, at a GOR of 10 m3/m3.

Phase behavior experiments have identified several surfactant systems that develop high solubilization ratios and low interfacial tension with a specific dead paraffinic crude oil at specific salinities. The purpose of this work is to test these surfactant systems with reconstituted live crude. Emulsion screening tests were performed in sight cells where an equilibrium amount of solution gas is dissolved in the crude at reservoir pressure (1100 psi). The results indicate that the surfactant is relatively more soluble in the oil phase under these conditions. Thus a formulated chemical slug for field conditions should contain either less salinity or a more hydrophilic surfactant system than that used in formulations with dead crude. Phase behavior measurements estimate this offset to be approximately 0.25% less NaCl for the particular live crude in this study. The relevance of this offset is shown by comparing the results of dead crude core floods with a live crude core flood. A control experiment pressurizing oil with nitrogen at the same condition, 1100 psi did not show enhanced relative surfactant solubility in the oil phase.

Phase-behavior experiments have identified several surfactant systems that develop high solubilization ratios and low interfacial tension (IFT) with a specific dead paraffinic crude oil at specific salinities. The purpose of this work is to test these surfactant systems with reconstituted live crude. Emulsion-screening tests were performed in sight cells where an equilibrium amount of solution gas is dissolved in the crude at reservoir pressure (1,100 psi). The results indicate that the surfactant is relatively more soluble in the oil phase under these conditions. Thus, a formulated chemical slug for field conditions should contain either less salinity or a more hydrophilic surfactant system than that used in formulations with dead crude. Phase-behavior measurements estimate this offset to be approximately 0.25% less NaCl for the particular live crude in this study. The relevance of this offset is shown by comparing the results of dead-crude corefloods with a live-crude coreflood. A control experiment pressurizing oil with nitrogen at the same condition, 1,100 psi, did not show enhanced relative surfactant solubility in the oil phase.

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A one-spot EOR pilot was successfully completed to demonstrate the efficacy of a lab-optimized ASP formulation to mobilize remaining oil from a giant sandstone reservoir in Kuwait. This one-spot EOR pilot, which also referred to as a Single Well Chemical Tracer (SWCT) test, was a significant milestone in de-risking ASP flooding for multi-well pilot implementation. The vertical zone of investigation for the Raudhatain Zubair (RAZU) SWCT was chosen to be a confined channel sand with relatively homogeneous and representative properties in a producer near the proposed pilot area. Two SWCT tests were performed and the difference in residual oil saturation from post water flood and post ASP injection tracer tests quantitatively determines the displacement efficiency of the ASP slug. The tracer chemicals for the tests included a hydrolyzing, partitioning tracer (ethyl acetate) and two alcohols (n-propyl alcohol and isopropyl alcohol) that serve as cover tracer and material balance tracer, respectively, to ensure robustness of test interpretation. The water flood SWCT test showed ideal behavior with well-defined profiles. Interpretation of this test was accomplished using a single layer model and showed that at the end of the water flood, the residual oil saturation to water was 0.24 ± 0.02% in the 23 -ft interval for the SWCT test. The ASP tracer test was complicated due to poor injectivity, well mechanical issues, and dilution from a zone which did not accept any SWCT test injection fluids but contributed substantially to production. Due to the dilution from another zone, the ASP tracer test profiles were more dispersed than the water flood tracer test but were adequately modeled using a two-layer model with irreversible flow. Analysis of the ASP SWCT test showed that the average oil saturation was reduced to 0.06 ± 0.05%, which represents a ~67% reduction in residual oil saturation. Despite poor injectivity leading to a reduced polymer drive and taper injection and dilution from another zone resulting in a non-idealized tracer response, careful interpretation of the SWCT test measurements resulted in a reliable estimate of the post-ASP oil saturation. The SWCT test results demonstrate the feasibility of applying ASP flooding to increase oil recovery from a giant high-temperature sandstone reservoir in North Kuwait.