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Collaborating Authors
Society of Petroleum Engineers Journal
Abstract This paper investigates the role of oil aromaticity in miscability development and in the deposition of heavy hydrocarbons during CO2, flooding. The results of phase equilibrium measurements, compositional studies, sandpack displacements, and consolidated corefloods are presented. Reservoir oil from the Brookhaven field and presented. Reservoir oil from the Brookhaven field and synthetic oils that model natural oil phase behavior are examined. Phase compositional analyses Of CO2/synthetic-oil mixtures in static PVT tests demonstrate that increased oil aromaticity correlates with improved hydrocarbon extraction into a CO2-rich phase. The results of tertiary corefloods performed with the synthetic oils show that CO2-flood oil displacement efficiency is also improved for the oil with higher aromatic content. These oil aromaticity influences are favorable. Reservoir oil experiments show that a significant deposition of aromatic hydrocarbon material occurs when CO2, contacts highly asphaltic crude. Solid-phase formation was observed in phase equilibrium and displacement studies and led to severe plugging during linear flow through Berea cores. It is unclear how this solid phase will affect oil recovery on a reservoir scale. Introduction Several reports suggest that oil aromaticity affects the CO2, displacement process of reservoir oil. Henry and Metcalfe noted the absence of multiple-liquid phase generation in displacement tests performed with a crude oil of low aromatic content. Holm and Josendal showed that when a highly paraffinic oil was enriched with aromatics, the slim-tube minimum miscibility pressure (MMP) decreased and oil recovery improved. Qualitative differences in the phase behavior of two crudes with contrasting aromatic contents prompted the suggestion by Monger and Khakoo that increased oil aromaticity correlates with improved hydrocarbon extraction into a CO2-rich phase. Clementz discussed how the adsorption of petroleum heavy ends, like the condensed aromatic ring structures found in asphaltenes, can alter rock properties. Laboratory studies have shown that improved oil properties. Laboratory studies have shown that improved oil recoveries in tertiary CO2 displacements benefited from changes in wetting behavior apparently, induced by asphaltene adsorption. Tuttle noted that CO2, appears to reduce asphaltene solubility and can cause rigid film formation. In these respects, oil aromaticity may also account for phase-behavior/oil-recovery synergism. Asphaltene deposition, though not a problem during primary and secondary recovery operations, was primary and secondary recovery operations, was reported in the Little Creek CO2 -injection pilot in Mississippi. Wettability alteration from asphaltene precipitation appears to have explained the results of low residual oil at high water-alternating-gas ratios in the Little Knife CO2, flood minitest in North Dakota. This paper provides detailed laboratory data from phase equilibrium measurements, compositional studies. sandpack displacements, and consolidated corefloods that illuminate the role of aromatics in miscibility development and in solid-phase formation during CO2 - flooding. The results for synthetic oils that model crude-oil behavior suggest that CO2-flood performance will benefit from increased oil aromaticity. The interpretation of reservoir oil results is more difficult. The precipitation of highly aromatic hydrocarbon material is observed when CO2, contacts Brookhaven crude. One purpose of this paper is to examine the variables that influence asphaltene precipitation. Near the wellbore, solid-phase formation might precipitation. Near the wellbore, solid-phase formation might reduce injectivity or impair production rates. Perhaps in other regions of the reservoir, altered permeability and/or wettability caused by solid-phase deposition might improve the ability of CO2, to contact oil. Additional work is needed to determine which potential benefits of oil aromaticity are significant on the reservoir scale. Advances in computer-implemented equations of state are making the prediction of CO2,/hydrocarbon phase behavior easier and more reliable. When an equation of state with CO2/reservoir-oil mixtures is used, an important consideration is the characterization of the heavy hydrocarbon components. One characterization method that appears to match the experimental data accurately in the critical point region for rich-gas/reservoir-oil mixtures is based on assigning separate paraffinic, aromatic, and naphthenic cuts. An additional aim of this study is to provide experimental data in assisting similar modeling provide experimental data in assisting similar modeling efforts for CO2/reservoir-oil mixtures. Experimental phase equilibrium data for mixtures containing CO2, and phase equilibrium data for mixtures containing CO2, and heavy hydrocarbons, particularly aromatics, are scarce. The behavior of multicomponent CO2,/hydrocarbon systems is not readily deduced from the phase equilibria of binary or ternary systems. Materials and Methods Phase Equilibrium Studies. A schematic diagram of the Phase Equilibrium Studies. A schematic diagram of the apparatus used in the phase-behavior experiments appears in Fig. 1. A detailed description of the equipment, procedures, chemicals, and analytical methods used is given procedures, chemicals, and analytical methods used is given in Ref. 10. SPEJ P. 865
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > North Dakota (0.89)
- North America > United States > Mississippi > Brookhaven Field (0.89)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract This paper presents a set of curvilinear coordinate transformations that lead to no mixed derivative terms in transformed flow equations. The transformations are created by examining the transformed flow equations and by showing that the mixed derivative terms are zero if the transformation satisfies a system of differential equations that depend on the geometry and rock property distribution within the reservoir. Numerical examples with a black-oil simulator are presented to show the increased accuracy resulting from the use of the curvilinear coordinate system and the importance of eliminating the mixed derivative terms. Introduction The accurate and efficient simulation of fluid flow in a reservoir is highly dependent on the choice of the mesh upon which discrete flow equations are to be solved. In many situations, a simulation conducted on a curvilinear coordinate system is advantageous. Many authors have reported on the advantages of solving reservoir simulation problems with a curvilinear coordinate system. problems with a curvilinear coordinate system. These advantages include the elimination of grid-orientation effects, improved modeling of reservoir geometries, and reductions in CPU time. Solving a problem on a curvilinear coordinate grid system is equivalent to transforming the reservoir into a rectangle and then solving the transformed problem on the rectangle. The transformed reservoir flow equations, however, will generally contain mixed derivative terms. In turn, these terms can alter the structure of the matrix that results from discretizing the flow equations. If the structure of the coefficient matrix is altered, the efficient solvers designed for use in reservoir simulation cannot be used without major modifications. One method for eliminating the mixed derivative terms is to use an orthogonal coordinate system. This system, however, does not eliminate the mixed derivative terms for an anisotropic permeability distribution. Several authors claim that the mixed derivative terms are small and, therefore, may be neglected. This is not the case, however, with large anisotropies. To maintain the inherent advantage of the curvilinear coordinate system, we found it necessary to minimize the effect of the mixed derivatives. This paper presents a class of curvilinear coordinate transformations that lead to no mixed derivative terms. The transformations maintain the advantages of a curvilinear coordinate grid system while avoiding the use of mixed derivative terms. The transformations are generated by examining the transformed flow equations and by showing that the mixed derivative terms are zero if the transformations satisfy a system of differential equations. These equations are based on the geometry and rock property distribution within the reservoir. The resulting system of differential equations is solved by a finite-element method (FEM) developed by Aziz and Leventhal. We begin with the derivation of the curvilinear coordinate transformation and how the mixed derivative terms are eliminated. The FEM is outlined briefly, followed by a description of the inverse transformation used to construct the curvilinear grid. Numerical examples with a black-oil simulator are presented to show the increased accuracy resulting from the use of the curvilinear coordinate system, the importance of accurately representing the reservoir geometry, and the importance of eliminating the mixed derivative terms. Mathematical Formulation The scope of this study is limited to two-dimensional (2D) reservoir flow problems. The transformations developed are applicable to complex transient and multiphase problems. However, it is sufficient to consider the model for the flow equations given in Eq. 1. .......(1) (See Appendix for more details.) It is assumed that the reservoir is banded by four curves, as shown in Fig. 1. The top and bottom curves represented by f1 and f2 are functions of x, while the sides, g1 and g2, are functions of y. The coordinates of the four corner points, c1, c2, c3, and c4, are (x1, y1), (x2, y2), (x3, y3), and (x4, y4), respectively. SPEJ p. 893
Abstract Elementary borehole- and perforation-stability problems in friable clastic formations for unrestricted fluid flow between reservoir rock and underground opening are treated on the basis of linear poroelastic theory. Thermal stress effects caused by a temperature difference between reservoir and borehole fluids can be predicted from the mathematical similarity of poro- and thermoelasticity. A tension-failure condition applies for the prediction of hydraulic fracture initiation in a formation around injection wells. The resulting equations are partially well-known. Similarly, a uniaxial compression-failure condition should predict perforation failure leading to sand influx in production wells. The major difference between these situations is that, at sufficient depth of burial, the tensile strength of a friable rock mass has only a minor effect on the fracturing pressure level, but the actual value of the compressive strength plays a crucial role in the prediction of sand-influx conditions. Practical suggestions for resolving the latter are given. Introduction This paper discusses borehole- and perforation-stability problems as encountered in friable sandstone formations that have in common free fluid flow between a reservoir and an underground opening. Such a condition prevailsduring fluid production through either casing perforations or open hole and during injection of fluids into a reservoir for pressure maintenance, gas conservation, tertiary oil recovery, or well stimulation. In the absence of a membrane (such as a filter cake) at the rock/hole interface, the effective stress normal to the rock surface is zero. Rock failure can result either in tension during fluid injection or in compression during fluid production. Because one of the principal effective stresses (the radial stress) is zero and the effect of the intermediate principal effective stress is small, failure is of either the unconfined tension or compression type. Rock failure resulting from fluid production from friable sandstones causes sand-particle influx. Failure caused by fluid injection means either planned or unintentional formation fracturing. The production technologist has to foresee such failure conditions as a function of changes in the stress regime with time. He has to start with a best possible estimate of the initial in-situ state of stress. On the basis of log data and core sample analysis, relevant rock deformation and strength properties must be determined next. Finally, an estimate of changes in the stress field resulting from prolonged production or injection must be made. Problem Areas Formation Particle Influx in Production Wells. Although significant improvements have been made in well-completion techniques aimed at sand-particle retention by both gravel packing and sand consolidation, straightforward production through casing perforations is the preferred production method because of minimum costs and maximum usage of well-flow potential. Moreoever, gravel packing long intervals of strongly deviated holes remains a difficult, expensive operation to perform, while sand consolidation processes for oil wells at temperatures above 75 degrees C [167 degrees F] are not available commercially. Friable formation sands i.e., formations that have some strength of their own-do not necessarily present a sand-influx problem initially. Sand production may develop gradually in time, once total drawdown increases and/or water breakthrough occurs. Deviated boreholes may encounter less favorable stress concentrations around perforations than vertical holes. All in all, it is necessary to predict the sand-influx potential of a well as soon as possible after drilling to serve as a basis for a completion policy. A perforation pattern that both results in production from only the more competent zones and enables delivery of the required well production capacity could be implemented. Formation Fracturing Around Injection Wells. A familiar type of formation failure is fracturing in tension around injection wells. Formation fracturing always occurs when the injection pressure surpasses the formation breakdown pressurei.e., the fluid pressure that brings the hoop stress around the opening in a tension equal to the tensile strength. Once initiated at or below this pressure level (because the formation may contain natural fractures), fracturing proceeds while the injection pressure surpasses the least principal in-situ total stress. The instantaneous shut-in pressure recorded during or after a fracturing job provides the best value of the least principal total stress component. The in-situ state of stress is not necessarily a constant during the production life of a reservoir. Changes both in reservoir pressure and in temperature adjacent to a well affect the local stress field in the formation. The effect of reservoir pressure variations on formation fracturing potential is well-known. Breckels and van Eekelen explicitly account for this effect. It is less recognized that in deeper formations cooling of the borehole surroundings by injection of liquids at near-surface temperature causes reservoir-rock shrinkage, leading to a reduction in both fracture initiation and propagation pressure. SPEJ P. 848^
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract Homogeneous core samples are needed for EOR experiments. We have devised a simple test for detecting the presence of nonuniformities in cores. The test consists of presence of nonuniformities in cores. The test consists of measuring the pressure drop across the core during a two-phase immiscible displacement experiment. We show that for a constant injection rate, the pressure drop will be linear with time provided that the core is homogeneous. In situations for which the initial section of the core is homogeneous, but the properties are not uniform in a latter section of the core, the location of the position where the rock properties fast change may be approximately determined. The effect of heterogeneities on the pressure-drop profile is demonstrated with analytical solutions and profile is demonstrated with analytical solutions and laboratory experiments. Introduction Core samples are used routinely for EOR or relative permeability experiments. For such experiments, selection permeability experiments. For such experiments, selection of a homogeneous core sample is necessary. Visual inspection of the core is not sufficient to ensure homogeneity. Often, vugs or shale barriers may be present, which may invalidate experimental results. In this paper, a simple test to detect the presence of core heterogeneities is devised. The scale of heterogeneities considered corresponds to the usual macroscopic description of porous medium properties. The properties of a porous medium (e.g., the properties. The properties of a porous medium (e.g., the porosity and permeability) at any particular location refer porosity and permeability) at any particular location refer to average quantities for some appropriate (small) representative volume element. In this way, each (locally averaged) property is defined at every point within the medium, the collection of which defines the representation of each property as a function of position. If each macroscopic property has the same value at all positions, the medium is said to be homogeneous. Otherwise, the medium is heterogeneous. A more complete discussion of macroscopic properties and heterogeneities can be found in Refs. 1 through 3. The macroscopic scale is a natural one to use for core selection because attempts to model coreflood experiments or to estimate properties of the porous medium on the basis of measured flow data generally will use mathematical models that use macroscopic properties. A homogeneous core sample is necessary for the experimental determination of relative permeabilities from displacement experiments. Explicit methods for estimating relative permeabilities from displacement data are based on the permeabilities from displacement data are based on the Buckley-Leverett model, in which the core is assumed to be homogeneous. The absolute permeability generally is determined from a single-phase flow experiment and thus represents an average value for the entire core. If the core is not homogeneous, so that the absolute permeability takes on different values in different locations permeability takes on different values in different locations in the core, errors will appear in the relative permeability estimates. Although the magnitude of the errors will depend on many factors, a macroscopically homogeneous sample is always preferred. Note that heterogeneities may also be defined on a microscopic scale. A porous medium that is macroscopically homogeneous may be microscopically heterogeneous. In fact, this typically would be the case because few real porous media structures are microscopically homogeneous. In this paper, we develop a test for detecting the presence of macroscopic heterogeneities in core samples. presence of macroscopic heterogeneities in core samples. The test is conducted by displacing the fluid that initially saturates the porous medium with a second fluid that is immiscible with the displaced fluid. The pressure drop across the core is recorded up to the time of breakthrough of the displacing fluid. The test is based on the observation that, with a constant injection rate and incompressible fluids, the pressure drop will be linear with time provided that the core is homogeneous. It is also shown provided that the core is homogeneous. It is also shown that, if the porosity and permeability for a heterogeneous core may be approximated as functions of the longitudinal spatial dimension, the pressure drop will be linear with time provided that the region in which both fluid phases are flowing simultaneously has uniform properties. The detection of heterogeneities by this method is discussed and illustrated with analytical solutions for the displacement process and with laboratory experimental data. Theory We consider here a displacement experiment with two incompressible fluids. Initially, the core is saturated with one fluid and the other fluid is injected at one end. For example, if the core initially contains only oil or air, water might be injected at one end. The core could contain the irreducible saturation of the displacing fluid initially, although this is not experimentally convenient and is not necessary for conducting the test. The pressure drop across the core is recorded through the time of breakthrough of the displacing fluid at the core outlet. SPEJ P. 909
- Geology > Geological Subdiscipline > Geomechanics (0.61)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
Abstract Prominent examples of linear flow behavior in-the well test Prominent examples of linear flow behavior in-the well test literature describe flow within or to a fracture penetrated by a producing well. The characteristic pressure transients generally producing well. The characteristic pressure transients generally are exhibited in the early portion of a well test and are followed by infinite-acting radial flow behavior and/or boundary effects. In contrast, if a formation is of a predominantly linear shape, linear flow is expected to develop in late time. In this paper, analyses of interference, drawdown, and buildup tests that are applicable to linear flow systems are described theoretically and illustrated by practical examples. The necessary equations for the analyses are provided for testing oil, gas, and geothermal steam wells. In elongated linear flow systems, the pressure transient behavior associated with linear flow occurs late in the drawdown or buildup test. The type curves provided in this work show that this pressure behavior is distinguishable from conventional well tests, pressure behavior is distinguishable from conventional well tests, particularly in interference tests. particularly in interference tests. Introduction Interest in linear flow geometry was limited for a long time to water influx applications. Miller I provided solutions for pressure distributions in semi-infinite- or finite-length linear pressure distributions in semi-infinite- or finite-length linear aquifers assuming water influx into the oil zone at a constant flow rate. Ehlig-Economides et al. 2 and Ehlig-Economides and Economides recently developed methods for analyzing geothermal well tests in a predominantly linear flow system. This work was motivated by the presence of parallel linear faults that are predominant in geothermal regions, such as the one shown in Fig. 1. Methods for interference analysis and for drawdown testing of geothermal steam wells were presented. Linear flow geometry currently is cited as a fairly common occurrence in low-permeability gas fields. Kohlhaas et al. provided a case study of linear flow behavior for a gas well completed in a channel-like reservoir and equations for analyzing the linear flow portion of drawdown and buildup tests. Stright and Gordon examined rate-decline behavior in gas wells in the Piceance basin in northwest Colorado that exhibited apparent linear flow behavior. In one case, the well penetrated a fracture in a low-permeability marine sand in which a number of long, natural fractures were present and appeared to be related to extensive faulting in the area. In another case, the well was completed in a long, narrow sand body shown by outcrops in the same area. A recent paper by Nutakki and Mattar provided solutions for drawdown vs. time for linear flow geometry. The solutions are identical to the work done by Ehlig-Economides and Economides for geothermal steam wells. However, the method of analysis, which made use of a "pseudoskin" factor, was distinctly different. In this paper, the previous methods of interference and drawdown analysis for geothermal wells in a linear flow system are reintroduced with additional coefficients for oil- and gas-well testing. In another paper, the drawdown behavior of fractured wells in the predominantly linear flow system is presented in detail. Theory In Fig. 1, the geological map from a geothermal region shows linear faults running parallel for several hundred feet. If the regional faults provide impermeable boundaries to flow, then a particular well may drain a volume best described as a long, narrow particular well may drain a volume best described as a long, narrow channel. In Fig. 2, schematics of several types of depositional environments show possible oil- and gas-reservoir geometries that would result in predominantly linear flow. These formations, which generally are long, narrow shapes, may be the results of river meander point bars, oxbow lakes, river channels, or tectonic breccias. The model used for this work employs the diffusivity equation, which requires assumptions concerning the formation and fluid properties, such as homogeneous and isotropic formation, horizontal monophasic Darcy flow, fluid of small and constant compressibility, and constant viscosity. The boundary conditions and appropriate dimensionless variables are defined separately for interference analysis and for drawdown/buildup analysis. Interference Analysis For interference analysis, the active well is located at the center of a rectangular cylinder of infinite length and is approximated by a planar source, as depicted in Fig. 3. The cross section of the cylinder is assumed to be a rectangle with height h and width b. The planar source boundary condition for the linear flow model is analogous to the vertical line source for horizontal radial flow. For drawdown analysis, a model incorporating wellbore storage and skin is required, as will be discussed later in this paper. SPEJ P. 839
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- Africa > Tanzania > Indian Ocean > K Formation (0.99)
Abstract Over the past 20 years, a number of studies have reported temperature effects on two-phase relative permeabilities in porous media. Some of the reported results, however, have been contradictory. Also, observed effects have not been explained in terms of fundamental properties known to govern two-phase flow. The purpose of this study was to attempt to isolate the fundamental properties affecting two-phase relative permeabilities at elevated temperatures. Laboratory dynamic-displacement relative permeability measurements were made on unconsolidated and consolidated sand cores with water and a refined white mineral oil. Experiments were run on 2-in. [5.1-cm] -diameter, 20-in. [52.-cm] -long cores from room temperature to 300F [149C]. Unlike previous researchers, we observed essentially no changes with temperature in either residual saturations or relative permeability relationships. We concluded that previous results may have been affected by viscous previous results may have been affected by viscous instabilities, capillary end effects, and/or difficulties in maintaining material balances. Introduction Interest in measuring relative permeabilities at elevated temperatures began in the 1960's with petroleum industry interest in thermal oil recovery. Early thermal oil recovery field operations (well heaters, steam injection, in-situ combustion) indicated oil flow rate increases far in excess of what was predicted by viscosity reductions resulting from heating. This suggested that temperature affects relative permeabilities. One of the early studies of temperature effects on relative permeabilities was presented by Edmondson, who performed dynamic displacement measurements with crude performed dynamic displacement measurements with crude and white oils and distilled water in Berea sandstone cores. Edmondson reported that residual oil saturations (ROS's) (at the end of 10 PV's of water injected) decreased with increasing temperature. Relative permeability ratios decreased with temperature at high water saturations but increased with temperature at low water saturations. A series of elevated-temperature, dynamic-displacement relative permeability measurements on clean quartz and "natural" unconsolidated sands were reported by Poston et al. Like Edmondson, Poston et al. reported a decrease in the "practical" ROS (at less than 1 % oil cut) as temperature increased. Poston et al. also reported an increase in irreducible water saturation. Although irreducible water saturations decreased with decreasing temperature, they did not revert to the original room temperature values. It was assumed that the cores became increasingly water-wet with an increase in both temperature and time; measured changes of the IFT and the contact angle with temperature increase, however, were not sufficient to explain observed effects. Davidson measured dynamic-displacement relative permeability ratios on a coarse sand and gravel core with permeability ratios on a coarse sand and gravel core with white oil displaced by distilled water, nitrogen, and superheated steam at temperatures up to 540F [282C]. Starting from irreducible water saturation, relative permeability ratio curves were similar to Edmondson's. permeability ratio curves were similar to Edmondson's. Starting from 100% oil saturation, however, the curves changed significantly only at low water saturations. A troublesome aspect of Davidson's work was that he used a hydrocarbon solvent to clean the core between experiments. No mention was made of any consideration of wettability changes, which could explain large increases in irreducible water saturations observed in some runs. Sinnokrot et al. followed Poston et al.'s suggestion of increasing water-wetness and performed water/oil capillary pressure measurements on consolidated sandstone and limestone cores from room temperature up to 325F [163C]. Sinnokrot et al confirmed that, for sandstones, irreducible water saturation appeared to increase with temperature. Capillary pressures increased with temperature, and the hysteresis between drainage and imbibition curves reduced to essentially zero at 300F [149C]. With limestone cores, however, irreducible water saturations remained constant with increase in temperature, as did capillary pressure curves. Weinbrandt et al. performed dynamic displacement experiments on small (0.24 to 0.49 cu in. [4 to 8 cm3] PV) consolidated Boise sandstone cores to 175F [75C] PV) consolidated Boise sandstone cores to 175F [75C] with distilled water and white oil. Oil relative permeabilities shifted toward high water saturations with permeabilities shifted toward high water saturations with increasing temperature, while water relative permeabilities exhibited little change. Weinbrandt et al. confirmed the findings of previous studies that irreducible water saturation increases and ROS decreases with increasing temperature. SPEJ P. 945
- North America > United States > Idaho > Ada County > Boise (0.44)
- North America > United States > West Virginia (0.24)
- North America > United States > Pennsylvania (0.24)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
Kortekaas, T.F.M., SPE, Shell Research B.V. Abstract Festoon crossbedding is a typical sedimentary structure in sandstone reservoirs. It is especially common in fluvial deposits. The important elements are the foreset laminae, which vary in permeability, and the bottomsets of lower permeability. To understand the complex, direction-dependent displacement characteristics of a crossbedded reservoir zone, we first conducted numerical simulations on a centimeter scale in a small part of a water-wet crossbedded reservoir zone. The simulations indicate that, during water/oil displacement, considerable amounts of movable oil initially are left behind in the higher-permeability foreset laminae with fluid flow perpendicular to the foreset laminae, while with flow parallel to the foreset laminae the displacement efficiency is good. To describe the displacement characteristics on a reservoir scale, we developed a procedure for calculating direction-dependent pseudo relative-permeability and capillary-pressure curves to be used as input for the simulations of water/oil displacement in a crossbedded reservoir zone. On a reservoir scale, the displacement characteristics in a water-wet crossbedded reservoir zone are slightly more favorable with the main fluid flow perpendicular to the foreset laminae. perpendicular to the foreset laminae. In addition, the sensitivity of the displacement characteristics to moderate reductions in interfacial tensions (IFT's) and to increases in water viscosity was investigated, both on a centimeter scale and on a reservoir scale. The simulations indicate the potential for substantial improvement in recovery from crossbedded reservoir zones if diluted surfactant or polymer is added to the drive water. Introduction Detailed studies of the effect of reservoir heterogeneities on water/oil displacement characteristics have been conducted on a well-to-well (layering) scale and on a pore scale, but few studies on an intermediate scale have been done. Therefore, we embarked on a study of the effect of centimeter-scale heterogeneities on water/oil displacement characteristics. We studied festoon crossbedding, one of the typical sedimentary structures in sandstone reservoirs, particularly common in fluvial deposits. A schematic particularly common in fluvial deposits. A schematic representation of a small part of a crossbedded reservoir zone is given in Fig. 1A. The important elements are the foreset laminae, which vary in permeability, and the bottom-sets, which are of lower permeability. The width of the foreset laminae is exaggerated in Fig. 1A; typically it is a few centimeters. First, we will discuss a mathematical simulation study in a very limited area of a water-wet crossbedded reservoir zone (1.97 ร 26.2 ร 0.66 ft [0.6 ร 8 ร O.2 m]). After a brief discussion of the water/oil displacement characteristics near a single permeability transition, we present the water/oil displacement characteristics in some cross sections of a simplified model (Fig. 1B) of a small part of a crossbedded reservoir zone. In addition, their sensitivity to moderate reductions in IFT's and increases in water viscosity are discussed. Second, we describe the effect of crossbedding on water/oil displacement characteristics on a reservoir scale, discuss a procedure for calculating dynamic, direction-dependent pseudo relative-permeability and capillary-pressure curves, and present the results of a reservoir-scale mathematical simulation study, including the pseudo-properties. Also, the sensitivity of the results to changes pseudo-properties. Also, the sensitivity of the results to changes in IFT and water viscosity is discussed. One-Dimensional Water/Oil Displacement Characteristics Near an Abrupt Permeability Transition Permeability Transition suppose we have a one-dimensional (1D) system consisting of two zones with different absolute, but identical relative, permeabilities. Furthermore, the system is horizontal and contains oil and connate water. The Buckley-Leverett first-order partial differential equation describes the water/oil displacement in each zone.In the absence of capillary and gravitational forces, the water fractional flow Fwo) is given by Eq. 1, together with Eq. 2, usually leads to a sharp shock front: at each location, water saturation will instantaneously jump from connate water to shock-front saturation when the water arrives. SPEJ p. 917
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.94)
Abstract A thermodynamic model is presented for modeling the partitioning of amphiphilic species between the different partitioning of amphiphilic species between the different phases of systems typically used for chemical flooding. phases of systems typically used for chemical flooding. The model, an extension of the pseudophase model by Biais et al. that can analyze only a four-component system, can work with five-component systems, including two partitioning amphiphilic species (e.g., two alcohols or one alcohol and a partitioning cosurfactant species). The self-association of alcohol in the organic phases, which results in a variable alcohol partition coefficient, is considered. Experiments to determine thermodynamic constants (which are entered into the model) are described for four-component systems, including one alcohol. The salinity dependence of these parameters is also studied. Brine/decane/isobutanol/TRS 10โ410 as well as brine/nonane/ isopropanol/TRS 10โ80 systems are considered. Some computations of pseudophase compositions for the five-component model and for various overall compositions are included. This partitioning model has been included in the chemical-flooding simulator developed at the U. of Texas; the results of this model have been presented in another paper. The model used for the presented in another paper. The model used for the binodal surface that is required to calculate phase compositions from pseudophase compositions is presented in this paper, as well as comparisons with experimental data for both four- and five-component systems. Reservoir simulation results are presented in Ref. 3. Introduction The possibility of reaching very low interfacial tensions (IFT) during the displacement of oil by surfactant solutions has been the subject of intense interest for some time. Because the decrease in IFT can be as much as several orders of magnitude, almost all the contacted oil can be mobilized by this process. However, the recovery rate has proved to be very sensitive to many parameters, and the process has to be designed carefully to achieve a good oil recovery. It is commonly recognized that the phase behavior is one of the most critical features for the phase behavior is one of the most critical features for the design of chemical oil-recovery processes. Many investigators have studied phase behavior of systems with various combinations of brine, oil, surfactants, and cosurfactants. Winsor introduced a very convenient classification of phase behavior for such systems. Type I is a lower-phase microemulsion (surfactant-rich phase) in equilibrium with an oleic phase; Type II is an phase) in equilibrium with an oleic phase; Type II is an upper-phase microemulsion in equilibrium with an aqueous phase, and Type III corresponds to a middle-phase microemulsion in equilibrium with both aqueous lower phase and oleic upper phase. The number of phases and their composition determined IFT's, viscosity, relative permeabilities and other hydrodynamic parameters on permeabilities and other hydrodynamic parameters on which the efficiency of the process is directly dependent. Components present in the reservoir during chemical flooding include water, electrolytes, oil, polymer, and the amphiphilic species surfactant and cosurfactant. From the viewpoint of chemical thermodynamics, the number of chemical species is very large if we consider every species of which oil, surfactant, and cosurfactant are made. Fortunately, some of these species behave collectively, so they can be considered a single pseudocomponent in the phase behavior description, thereby pseudocomponent in the phase behavior description, thereby making the study more tractable. For example, Vinatieri and Fleming considered brine a good pseudocomponent, which means that the ratio of salt to water is about the same in each phase. McQuigg et al.'s experiments yield similar conclusions. Even crude oil has been shown to be a good pseudocomponent with a fairly acceptable accuracy. Dealing with amphiphilic species is far more difficult. In some laboratory studies, surfactant can be a chemically pure component, but for field applications it is usually a complex blend, such as petroleum sulfonates. In the case of petroleum sulfonates, different monosulfonated or polysulfonated species are present with varied carbon polysulfonated species are present with varied carbon tails. Commercial nonionic surfactants, which generally are ethoxylated alcohols, show a broad distribution of ethylene oxide number (EON). In both cases, investigators have shown that these commercially available surfactants do not behave collectively but in some situations partition selectively between the phases. The cosurfactant generally is an alcohol or an ethoxylated alcohol. Although many research programs currently are devoted to the design of alcohol-free systems to avoid some of the drawbacks induced by its presence (lower solubilization parameters, higher IFT's), most of the commonly used systems include alcohol or even a blend of alcohols with different carbon chain lengths and/or branching. SPEJ P. 693
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.86)
Carter, Robert D., SPE, Amoco Production Co. Abstract This paper presents gas-production-rate results in type curve form for finite radial and linear flow systems produced at a constant terminal (bottomhole) pressure. These produced at a constant terminal (bottomhole) pressure. These results can be used in the analysis of actual gas and oil rate/time data to estimate reservoir size and to infer reservoir shape. The type curves are based on dimensionless variables that are a generalized form of those presented previously. In addition, an approximate drawdown previously. In addition, an approximate drawdown parameter is presented. Example applications that parameter is presented. Example applications that demonstrate the applicability of the type curves to a variety of reservoir configurations are given. The Appendix contains derivations of the dimensionless variables and the drawdown parameter. Introduction The gas-bearing rock in some low-permeability gas fields consists of sandstone lenses of uncertain but limited size. In such fields, the reservoir area and volume drained by individual wells cannot be inferred from well spacing. Moreover, good reserve estimates using plots of p/z vs. cumulative production are often not possible because of the difficulty of obtaining reservoir pressure from buildup tests. Therefore, reserve estimation techniques that use performance data, such as production rate as a function performance data, such as production rate as a function of time, are needed. Although this problem has been recognized, the techniques proposed in the past for application to gas reservoirs have been mostly empirical. The present work offers a method that is consistent with the basic theory of gas flow in porous media for analyzing production data to estimate reserves. This method will also provide some inference about reservoir shape. Type Curves Basic Assumptions Six basic assumptions are made in generating the type curves.The flow geometry is radial; therefore, the reservoir either is circular and is produced by a concentrically located well of finite radius or is a sector of a circle produced by the corresponding sector of the well (Fig. 1). produced by the corresponding sector of the well (Fig. 1). In the limit as, the flow regime becomes a linear one. Permeability, porosity, and thickness are constant throughout the reservoir. The pressure at the well radius (usually corresponding to the bottomhole flowing pressure CBHFP]) is held constant. The initial reservoir pressure is constant (independent of position). Non-Darcy flow is neglected. The flowing fluid is either a gas with viscosity and compressibility that vary with pressure or an oil with a constant viscosity/compressibility product. Definitions. The type curves are based on specially defined dimensionless time (tD), dimensionless rate (qD), a flow geometry parameter ( ), and a drawdown parameter ( ). These variables are defined by the following parameter ( ). These variables are defined by the following equations, which are derived in the Appendix. ............................ (1) ................................(2) ...............................(3) .....................(4) Results The type curves for rate as a function of time are presented in Fig. 2. A finite-difference radial-gas-flow simulator was used to generate the data for constructing the type curves. Two flow periods can be identified. The infinite-acting (or transient) period is that period before which the curves become concave downward. The transient period ends at to values ranging from about 0.15 to about 1.0, depending on the value of 17 that characterizes the curve. The curves are concave downward during the late-time or depletion period. Notice that the primary characterizing parameter during the infinite-acting period is, and is parameter during the infinite-acting period is, and is the characterizing parameter for late-time behavior (tD >1). The curves for = 1.234 (linear flow) are straight lines with a negative half-slope during the infinite-acting period. SPEJ p. 719
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
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Abstract A probability distribution, which incorporates the random occurrence of wave heights and the uncertainty in the force coefficients of the Morison equation, was derived for the forces on offshore structures. The random occurrence of wave heights was assumed to be described by a Weibull distribution, and the uncertainty in the force coefficients was assumed to be represented by a normal distribution. Wave force was assumed to be proportional to wave height raised to a power. The assumed distributions and force relationship may not describe exactly the actual problem within a general framework, but the assumptions are believed to be applicable to the range of wave heights and conditions occurring for the selection of static design criteria for the forces on offshore structures. The applicability of the assumptions is enhanced because the primary results are expressed as ratios, which require only relative accuracy and not quantitative accuracy. Introduction The wave forces on an offshore structure are determined by a wave theory (e.g., Stokes or stream function) that relates the water kinematics (velocity and acceleration) to the wave parameters (height and period) and a theory that relates the resulting pressures on the structure to the predicted water kinematics (e.g., the Morison equation or refraction theory). Generally, the Morison equation, which incorporates two force coefficients - the drag and inertia coefficients - is used. The wave parameters experienced by a structure during a storm are random. Also, inferred values of the force coefficients from field measurements indicate a random scatter from wave to wave caused by the random nature of the processes involved and imperfect wave and hydrodynamic theories. Therefore, the prediction of wave forces and, ultimately, the selection of design criteria for offshore structures involve both the random nature of the wave parameters (e.g., height) and the uncertainty in the force coefficients. Procedures for selecting wave heights for design criteria have received considerable attention and are well established; however, the problem of considering the uncertainty in the force coefficients has received little attention. Currently, there is no rational procedure to account generally for coefficient uncertainty except to use arbitrary, and potentially unrealistic, guidelines, such as the mean value plus a multiple of the standard deviation. The purpose of this paper is to provide a rational framework for dealing with the uncertainty in force coefficients. This framework is statistical and incorporates into the force statistics the uncertainty of the force coefficients and the random occurrence of the wave parameters. Background The wave force, Q, on an offshore structure is generally determined by the Morison equation,Equation 1 QD and QI are defined as the drag and inertia forces, respectively, per unit length acting normal to a structural element; CD and CI are the drag and inertia coefficients (i.e., the force coefficients); v and v are the water velocity and acceleration normal to the element; d is the element diameter; and ?w is the mass density of water.