Hydrocarbon gas injection projects are undertaken in order to maintain reservoir pressure, produce oil through swelling and reduce residual oil saturation by decreasing the interfacial tension (IFT). Along with local displacement efficiency, macroscopic sweep efficiency plays a dominant role in the success of gas injection projects, as recovery from the field depends strongly on reservoir geology and petrophysical properties. In this paper, a case study of one of the hydrocarbon gas injection pilots is discussed as the performance of the other two pilots has already been described in Kumar et al. 2015a. A five-spot pattern hydrocarbon gas injection pilot in tertiary mode has been carried out in a giant carbonate reservoir offshore Middle East, which has long peripheral water injection history. A comprehensive monitoring plan, including an observer well, was applied through time-lapse saturation logging, single well chemical tracer test (SWCTT), pressure measurements, production testing, and tracer campaign to assess the pilot performance and minimize uncertainties before large-scale application. This paper presents the overview of the pilot, monitoring plan and the findings which include microscopic and macroscopic sweep efficiency. The pilot areal sweep performance was affected by the existing pressure gradient of peripheral water injection while the vertical sweep efficiency was strongly affected by the reservoir heterogeneity. At the cessation of the pilot, a value of 6 ± 3% was measured from SWCTT in the producer well, which shows the robustness of the gas local displacement efficiency. The history match performed indicates that for the same pilot, the performance can be improved using horizontal line drive in place of five-spot pattern and it can further be enhanced through water-alternating-gas (WAG) injection. The learning from the three gas injection pilots is used in re-designing the future large-scale development plan and is described in details in Kumar et al., 2016a and 2016b.
Hydrocarbon gas injection is the most widely applied process after waterflooding, and is a promising enhanced oil recovery (EOR) injectant for use in Middle East carbonate oil fields. Gas injection improves microscopic displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can negatively impact the ultimate recovery due to viscous fingering and gravity override. This paper describes two gas injection pilots that have been implemented in offshore Middle-East carbonate reservoirs, a secondary and a tertiary gas injection through line drive to assess injectivity, productivity, macroscopic sweep efficiency, flow assurance and operational efficiency in a field that has long water-injection history. A strong monitoring plan, including an observer well, was applied through time-lapse saturation logging, pressure measurements, production testing, tracer campaign, etc. to evaluate the pilot efficiency and address key uncertainties upfront prior to full-field application.This paper describes the pilot performance in the context of full-field development, local and macroscopic displacement efficiency, flow assurance issues, and operational learnings. The gas injection performance is strongly impacted by reservoir heterogeneity, gravity segregation and the existing pressure gradient, and the history match performed indicates near-miscible or miscible behavior depending upon local pressure regimes, which thus govern the ultimate recovery. The history match also shows that for the same pilot, performance can be further improved through water-alternating-gas (WAG) injection, resulting in a viable development scheme for full-field implementation.
Summary Hydrocarbon-gas injection is one of the most widely applied processes in the oil industry and is a promising enhanced-oil-recovery (EOR) method for use in Middle East carbonate oil fields. Gas injection improves the microscopic-displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can negatively affect the ultimate recovery because of viscous fingering and gravity override. This paper describes two gas-injection pilots that have been implemented in offshore Middle East carbonate reservoirs: a secondary and a tertiary gas injection through line drive to assess injectivity, productivity, macroscopic-sweep efficiency, flow assurance, and operational efficiency in a field that has a long water-injection history. A strong monitoring plan, including an observer well, was applied through time-lapse saturation logging, pressure measurements, production testing, and a tracer campaign to evaluate the pilot efficiency and address key uncertainties upfront before full-field application. This paper describes the pilot performance in the context of full-field development, local- and macroscopic-displacement efficiency, flow-assurance issues, and operational learnings. The gas-injection performance is strongly affected by reservoir heterogeneity, gravity segregation, and the existing pressure gradient, and the history match performed indicates near-miscible or miscible behavior depending upon local pressure regimes, which thus govern the ultimate recovery. The history match also shows that for the same pilot, performance can be further improved through water-alternating-gas (WAG) injection, resulting in a viable development scheme for full-field implementation.
The design of solvent-based and solvent assisted heavy oil recovery processes requires accurate predictions of phase behavior as straightforward as saturation pressures and as potentially complex as vapour-liquid-liquid equilibria and asphaltene precipitation. In this case study, saturation pressures of dead and live bitumen were measured in a Jefri PVT cell at different concentrations of a multi-component solvent at temperatures from 20 to 180°C. Saturation pressures and the onset of asphaltene precipitation were also measured for the bitumen diluted with n-pentane. The onset of precipitation was determined by titrating the bitumen with pentane and periodically circulating the mixture past a high pressure microscope.The data were modeled with the Advanced Peng-Robinson equation of state (APR EoS). The maltene fraction of the bitumen was characterized into pseudo-components based on extrapolated distillation data. The asphaltenes were characterized based on a Gamma distribution of the molecular weights of selfassociated asphaltenes. The APR EoS was tuned to match the saturation pressures by adjusting the binary interaction parameter between the solvent and the pseudo-components via a correlation based on critical temperatures. Rather than adjusting the interaction parameters for each pair of components, only the exponent in the correlation was adjusted. The role of mixing rules in correctly predicting the onset and amount of asphaltene precipitation is discussed.
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