Temperature observations taken in a well that traverses a steam-heated fracture in a tar sand formation allow estimates of the in-situ thermal parameters of the formation. They also indicate for the case presented the upward movement of a heat source at a constant velocity, suggesting the vertical growth of a permeable hot zone. This vertical movement can be modeled approximately with a thermal simulator. Comparison of numerical and analytic solutions, however, shows that very small finite-difference grid spacing is required to obtain the correct steam rise velocity with the simulator. The comparison between experimental and simulation results also provides an indication of the relative importance of the vertical reservoir permeability. Introduction In view of the number of projects under way in heavy oil and tar sand deposits, it seemed of interest to report on a set of temperature observations made during a steam injection project in the Athabasca tar sands. Such measurements permit estimates of the thermal parameters of the formation. as well as provide information on possible changes in the heat and fluid flow paths. In the case considered here, the formation was fractured horizontally at a depth of approximately 63.7 m (209 ft). The observation well, BT-4 in Ref. 2, traversed this fracture and was used to monitor the extent of heating of the formation above and below the fracture as steam flowed through at a pressure sufficient to keep the fracture open. In addition to analyzing field observations, we have used numerical simulation to model the vertical movement of the steam front. The refinement of the simulation by the appropriate number and size of grid blocks and the appropriate choice of formation parameters can be used to provide insight into the mechanisms involved in the heating process. Description of Observation Well In the well completion. after the hole for the temperature observer was drilled, a plastic rod with attached thermocouples was lowered into the well to position thermocouples above and below the location where the fracture was anticipated (Fig. 1). The assembly was then cemented in place, thus eliminating the possibility of convection within the well. Once the fracture had been generated, the temperature was maintained throughout the fracture by injected steam at 198 deg. C (388 deg. F). The injection steam pressure was sufficient to keep the fracture open. Results of Temperature Observations In Fig. 2 we have plotted dimensionless temperatures obtained from the thermocouples located at 1.12, 2.44, 3.35, and 4.88 m (4, 8, 11, and 16 ft) below the fracture plane as a function of time. These data may be described reasonably by the equation for one-dimensional (1D) heat conduction. (1) To achieve a fit with the data for Z=2.44, 3.35, and 4.88 m (8, 11, and 16 ft), a value of alpha =0.927 mm /s (0.862 sq ft/D) was used. SPEJ P. 575^
The analysis of underground oil-shale recovery processes requires knowledge of the mechanical properties of oil shale at various temperatures. The tensile strength, compressive strength. and Young's modulus are of special importance. The variation of these properties with temperature is important when assessing the strength of underground columns and confining walls for process cavities. This paper presents the results of an experimental study to quantify this temperature dependence. We found that both tensile and compressive strengths of oil shale show a marked decrease in strength as temperature increased. for a given richness. For example. for 15.6 gal/ton oil shale. the tensile strength at 400°F is only 28% of its room temperature value. For 19.2 gal/ton shale. the compressive strength at 400°F with 500-psi confining pressure is 43% of its value at room temperature. At a given temperature. both the tensile and compressive strengths decrease as richness increases. although the rate of decrease diminishes at richnesses of about 42 gal/ton and higher. Equations are developed to permit estimates of the various parameters involved. The compressive Young's moduli show a considerable decrease with temperature. At 400°F the modulus is reduced to 51 % of its room temperature value.
This paper deals with compressible fluid flow accompanied by solid deposition in a porous reservoir. The isothermal fluid flow is considered to be radial and follows Dorcy's law. The initially dissolved substances precipitate from the solution as a result of solubility reduction as the pressure declines. These deposits occumulate in the void spaces and hence inhibit the flow. An idealized model describing this transport mechanism has been proposed. On the basis of this model, a numerical technique has been developed to predict the amount of solid precipitation and the pressure distribution as functions of time and radial distance.The method is applied to the production performance of a reservoir containing mainly hydrogen sulfide saturated with elemental sulfur. The solid sulfur builds up rapidly in the vicinity of the production well. A very negligible amount is formed close to the impermeable outer boundary. It is shown that plugging by solid sulfur in the porous medium can be reduced either by reducing the production rate or by choosing closer well spacing.
On the basis of Peace River bitumen/brine flow experiments at elevated temperatures, tar relative permeability/saturation relations vary depending on the previous thermal history of the tar. The relative permeability curve for thermally unaltered tar is shifted toward the region of low water saturation, while that for thermally altered tar is closer to the Leverett oil permeability curve for water-wet unconsolidated sands. Oil permeability values for deasphalted tar lie at saturations intermediate between those of the thermally altered and unaltered tar.
Production of oil by expansion from a cylindrical reservoir composed of twoconcentric regions of different properties has been determined as a function oftime for a reservoir producing at constant terminal pressure.. The parametersinvolved are permeability, porosity, compressibility and oil viscosity. Resultsagree with those of a generally accepted method for uniform reservoirs when allparameters are taken as uniform. Cumulative production at any given time isreduced below that of the uniform reservoir when a region of considerably lowerpermeability adjoins the well; cumulative production increases when ahigh-permeability region adjoins the well. Curves are presented illustratingquantitative effects of these variations. INTRODUCTION Most petroleum reservoirs can be exploited by release of pressure andconsequent expansion of underground fluid. During part of the productionhistory of certain reservoirs by this mechanism, fluid compressibility can beconsidered small and constant. Cumulative fluid produced by this means as afunction of time was calculated for a uniform reservoir by van Everdingen andHurst.1 For certain cases where a production well has been damagedor where an acid treatment has been used, a zone of properties different fromthose of the reservoir may be created around the production well. In such acase, expansion of the reservoir fluid takes place in a system composed of twoconcentric cylindrical regions of different reservoir properties. Suchcomposite systems were studied in connection with heat flow byJaeger2 who presented a solution for temperature distribution in aradial system with an infinitely large outer radius. Similar heat flow problemshave been studied by other authors;3 Oil production from compositereservoirs was studied for constant production rate by Hurst,4Loucks and Guerrero,5 and Carter.6 THEORY This work considers constant terminal pressure. Cumulative flow iscalculated for a composite bounded system in which no flow takes place acrossthe outer boundary (Fig. 1). Since the flow is considered to be purely radial, the problem involves only one space dimension and time. It is convenient todefine the following dimensionless pressure drops (Fig. 1).
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