A broadly applicable methodology is presented to reliably predict crude-oil-liquid viscosity from a gas-chromatographic (GC) -assay composition only (C 30þ is recommended). The viscosity model employs a Walther-type correlation of double-log viscosity with log temperature to predict the viscosity of dead and live crude oils and mixtures. The model has three parameters: the slope and intercept of the Walther plot and a viscosibility factor to account for pressure effects. Simple mass-based mixing rules are applied on these three parameters to obtain mixture viscosity. The three parameters were correlated to component molecular weight (MW); therefore, a gas-chromatographic assay is the only required input apart from the temperature and pressure.The methodology was developed from a western Canadian (WC) data set of two bitumens, one heavy oil, and one condensate, and then tested on an independent data set of 10 conventional and heavy crude oils from the Gulf of Mexico, the Middle East, Asia, and Europe. The model provides untuned viscosity predictions within a factor of two of the measured values for dead and live crude oils ranging in viscosity from 0.5 to 500 000 mPaÁs. A single multiplier is used to tune the model. Models tuned to dead-oil data predict live-oil viscosities and those of mixtures of oils with solvents to within 30% of the measured values. Models tuned to the viscosity at the saturation pressure predict the effect of temperature and pressure to within 20% of the measured values.The method retains its accuracy when components are lumped into a few pseudocomponents and is suited ideally for use in simulators for accurate liquid-phase viscosity predictions over a wide range of compositions, pressures, and temperatures. It would be necessary to include the proposed mixing rules in numerical simulators. An additional advantage of the method is the reduction in viscosity measurements needed to construct an accurate viscosity model.

A 3-D geological model of the Kimmeridgian-Tithonian Manifa, Hith, Arab, and Upper Diyab formations in the area of the onshore Central Abu Dhabi Ridge was based on a newly established sequence stratigraphic, sedimentologic, and diagenetic model. It was part of an inter-disciplinary study of the large sour-gas reserves in Abu Dhabi that are mainly hosted by the Arab Formation. The model was used for dynamic evaluations and recommendations for further appraisal and development planning in the studied field. Fourth-order aggradational and progradational cycles are composed of small-scale fifth-order shallowing-upward cycles, mostly capped by anhydrite within the Arab-ABC. The study area is characterized by a shoreline progradation of the Arab Formation toward the east-northeast marked by high-energy oolitic/bioclastic grainstones of the Upper Arab-D and the Asab Oolite. The Arab-ABC, Hith, and Manifa pinch out toward the northeast. The strongly bioturbated Lower Arab-D is an intrashelf basinal carbonate ramp deposit, largely time-equivalent to the Arab-ABC. The deposition of the Manifa Formation over the Arab Formation was a major back-stepping event of the shallow-water platform before the onset of renewed progradation in the Early Cretaceous. Well productivity in the Arab-ABC is controlled mainly by thin, permeable dolomitic streaks in the fifth-order cycles at the base of the fourth-order cycles. This has major implications for reservoir management, well completion and stimulation, and development planning. Good reservoir properties have been preserved in the early diagenetic dolomitic streaks. In contrast, the reservoir properties of the Upper Arab-D oolitic/bioclastic grainstones deteriorate with depth due to burial diagenesis. A rock-type scheme was established because complex diagenetic overprinting prevented the depositional facies from being directly related to petrophysical properties. Special core analysis and the attribution of saturation functions to static and dynamic models were made on a cell-by-cell basis using the scheme and honoring the 3-D depositional facies and property model. The results demonstrated the importance of integrating sedimentological analysis and diagenesis with rock typing and static and dynamic modeling so as to enhance the predictive capabilities of subsurface models.

Viscous oil resources have great potential to help meet the future demand for petroleum products as conventional resources are depleted. Currently high temperature steam injection is the recovery process of choice, with high energy intensity and associated greenhouse gas emissions. The work presented here explores a low-temperature solvent-only injection strategy targeting fractured systems. The warm solvent is in the vapor phase when injected into the reservoir but will condense when it contacts the cold oil and reservoir rock (liquid extraction). After the system has reached the target operating temperature, the injected solvent remains in the vapor phase when it contacts the oil (solvent-enhanced gravity drainage). The experiments discussed in this work explore the key parameters (permeability, temperature/pressure, in situ injection rate, and solvent type) that influence each production mechanism. The primary impact of decreasing permeability is a proportional decrease in film gravity drainage rate. A decrease in temperature slows the mass transfer during the liquid extraction phase and decreases the drainage rate during the film gravity drainage phase. Increasing the in situ injection rate leads to improved liquid extraction because of higher concentration gradient in the solvent-rich liquid phase at the oil/solvent interface. Solvent type affects both mechanisms and changes the nature and amount of asphaltene precipitation. Pentane yields relatively less asphaltene precipitate than butane (18 wt % vs 11 wt % asphaltene content in residual oil). Residual oil saturation was observed to increase as permeability and/or temperature were decreased.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn this paper we will present the outcome of a study conducted to evaluate the feasibility of large scale injection of sour and/or acid gas into a low permeable carbonate reservoir to enhance oil recovery.Other than for disposal, H 2 S containing mixtures have rarely been injected as a miscible agent in oil recovery projects. Moreover, the very few projects that have actually been executed are relatively small (generally less than 10 MMscf/d).In this study different recovery processes were evaluated such as water flooding, lean gas injection, sour gas (natural gas with a large H 2 S content) injection, acid gas injection, acid gas (mixture of H 2 S and CO 2 ) after a slug of sour gas and CO 2 injection. To evaluate these different (EOR) recovery processes, a detailed reservoir description is essential and for this purpose element-models were used.The critical importance of a thorough understanding of reservoir geology and rock properties for miscible gas injection schemes has been confirmed by the experiences of water breakthrough and over-ride in a number of reservoirs in Abu Dhabi and the poor performance of some miscible gas injection projects in the industry.The simulation study shows that miscible acid gas injection is the preferred recovery mechanism for part of the reservoir under study. This is a result of several key factors, including the favorable miscibility with the native oil (lower miscibility pressure with reservoir crude), better solvent for asphaltene, a more favorable mobility ratio due to high acid gas viscosity and density and availability of large quantities of acid gas from the underlying formation. Acid gas is therefore an attractive, low cost, miscible, enhanced oil recovery agent, provided fully adequate corrosion mitigation procedures and HS&E management systems are implemented in the development.

No abstract