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Nature is inherently multiphase and multicomponent. Water being ubiquitous in nature, any oil and gas formation is necessarily multiphase. In general, conditions pertaining to fluid, commonly designated as “black oil,” show the presence of water, oil, and gas. For simplicity, previous chapters have dealt with single-phase fluid. This chapter presents the basics of modeling a black-oil reservoir. In this context, we present the necessary engineering concepts for multiphase flow in porous media, followed by the derivation of the flow equation for any component in the system in a 1-D rectangular reservoir. Then, using CVFD terminology, we present the component general flow equations in a multiphase, multidimensional system, which apply to interior and boundary reservoir blocks. From these component flow equations, the basic flow models of two-phase oil/water, oil/gas, and gas/water and three-phase oil/water/gas are derived. The accumulation terms in flow equations are expressed in terms of changes in the reservoir block unknowns over a time step. We present the equations for phase production and injection rates from single-block and multiblock wells operating with different conditions. The treatment of boundary conditions as fictitious wells is presented and discussed in detail. Methods of linearization of nonlinear terms in multiphase flow are discussed. We introduce two of the basic methods for solving the linearized multiphase flow equations, the implicit pressure–explicit saturation (IMPES) and simultaneous solution (SS) methods. Because this chapter forms an introduction to the simulation of multiphase flow, we present the two solution methods (IMPES and SS) as they apply to the two-phase oil/water flow model only. The extensions of these methods to other flow models are straightforward, whereas the application of additional solution methods, such as the sequential (SEQ) and the fully implicit methods, is discussed elsewhere. More recently, Mustafiz et al., 2008a , Mustafiz et al., 2008b developed a new solution technique that solves nonlinear equations without linearization. Recently, the possibility of generating multiple solutions in the form of cloud points, which can then be used to draw the boundary of probable solutions, has been discussed in the literature. Such analysis is likely to unlock future directions of knowledge-based simulation.

This chapter presents discretization of 1-D, 2-D, and 3-D reservoirs using block-centered grids in Cartesian and radial-cylindrical coordinate systems. As the name implies, the gridblock dimensions are selected first, followed by the placement of points in central locations of the blocks. In this, the distance between block boundaries is the defining variable in space. In contrast, the gridpoints (or nodes) are selected first in the point-distributed grid, which is discussed in Chapter 5 . Chapter 2 introduced the terminology for reservoir discretization into blocks. This chapter describes the construction of a block-centered grid for a reservoir and the relationships between block sizes, block boundaries, and distances between points representing blocks. The resulting gridblocks can be classified into interior and boundary gridblocks. Chapter 2 also derived the flow equations for interior gridblocks. However, the boundary gridblocks are subject to boundary conditions and thus require special treatment. This chapter presents the treatment of various boundary conditions and introduces a general flow equation that is applicable for interior blocks and boundary blocks. This chapter also presents the equations for directional transmissibilities in both Cartesian and radial-cylindrical coordinate systems and discusses the use of symmetry in reservoir simulation.

Wells in reservoir simulation are the most astute form of discontinuity. As such, the difficulties encountered due to boundary conditions are accentuated by the presence of wells. Yet, wells are paramount to reservoir evaluation because of the fact that engineering is all about optimizing well performance. In general, the contribution of any reservoir block penetrated by a well to the well flow rate is independent of the flow equation for that block. Such contribution has to be estimated separately from and then substituted into the flow equation for the wellblock. Fluid flow toward a well in a wellblock is radial regardless of the dimensionality of the flow problem. A well is modeled as a line source/sink term. In this chapter, the emphasis in 1-D and 2-D flow problems is on the estimation of the well geometric factor, while in 3-D flow problems, the focus is on the distribution of the well rate among the different blocks that are penetrated by the well. The estimation of the wellblock geometric factor is presented for a well hosted by one block and falling inside block boundaries and a well hosted by one block and falling on one or two of block boundaries (in 1-D and 2-D flow) that are reservoir boundaries. We present the production rate equation for a wellblock and the equations necessary for the estimation of the production rate or flowing bottom-hole pressure (FBHP) for wells operating under different conditions, which include (1) a shut-in well, (2) a specified well production rate, (3) a specified well pressure gradient, and (4) a specified well FBHP.

Discretization process creates inherent challenges involving proper representation of natural processes. The problem is accentuated by boundaries, which create discontinuities—an absurd condition for natural systems. Historically, the petroleum engineers have identified these problems and have attempted to address many problems that emerge from discretization and boundary conditions, which must be addressed separately. Few, however, have recognized that the engineering approach keeps the process transparent and enables modelers to remedy with physically realistic solutions. This chapter presents discretization of 1-D, 2-D, and 3-D reservoirs using point-distributed grids in Cartesian and radial-cylindrical coordinate systems. This chapter describes the construction of a point-distributed grid for a reservoir and the relationships between the distances separating gridpoints, block boundaries, and sizes of the blocks represented by the gridpoints. The resulting gridpoints can be classified into interior and boundary gridpoints. While Chapter 2 derives the flow equations for interior gridpoints, the boundary gridpoints are subject to boundary conditions and thus require special treatment. This chapter presents the treatment of various boundary conditions and introduces a general flow equation that is applicable to interior gridpoints and boundary gridpoints. This chapter also presents the equations for directional transmissibilities in both Cartesian and radial-cylindrical coordinate systems and discusses the use of symmetry in reservoir simulation.

In-situ combustion (ISC) is being carried out in the Quifa heavy oil reservoir in Colombia, employing four vertical inner wells and four deviated outer wells (inverted nine-spot pattern). Additionally there are four horizontal wells surrounding the pattern, which started producing one year before the combustion project was initiated. In order to evaluate the project performance key parameters, such as volumetric sweep efficiency and recovery factor must be estimated. Therefore, it is important to have reliable values of drainage area and oil in-place volumes since they are basics for the calculations. Given the complex nature of this reservoir, with a strong water drive, the estimation of the drainage area, oil in place and the recovery factor posed a major challenge. The reservoir is characterized by abrupt permeability and oil saturation changes, resulting in water channeling and well interference. This paper presents the methodology used to obtain the drainage area and current recovery factor of the ISC pilot project by using numerical reservoir simulation. It comprises the generation of oil drainage maps and cross-plots of what we called "Oil Displaced by Neighboring Wells, ODNW" as a function of time. This approach is more accurate than analytical methods for such complex reservoirs since those methods are based on ideal homogeneous reservoir conditions that assume uniform fluid displacement and a symmetrical advance of the combustion front. Results are presented for the oil in place, the drainage area, and the recovery factor at one year of air injection. These results are compared with those derived from analytical methods. The methodology was designed to be readily applicable to similar heavy oil reservoirs worldwide.

Over two-thirds of the original oil remains unrecovered in an oil reservoir, after primary and secondary recovery methods have been exhausted. Many chemically based oil recovery methods have been proposed and tested in the laboratory and field. Indeed, chemical oil recovery methods offer a real challenge in view of their success in the laboratory and lack of success in the field. The problem lies in the inadequacy of laboratory experiments on one hand, and the very limited knowledge of the reservoir characteristics on the other. Field test performances of polymer, alkaline, and micellar flooding methods are examined for nearly 50 field tests, results for which are tabulated. The oil recovery performance of micellar floods is the highest, followed by polymer floods. Alkaline floods have been largely unsuccessful. The reasons underlying success or failure are examined.

In terms of improving oil recovery in Catriel Oeste Field, a project was undertaken to determine the feasibility of applying an Enhanced Oil Recovery process by Polymerflood. A pilot was selected in two productive reservoirs projecting to start with polymer injection on August 1993. This paper describes the studies made for the pilot design and the conditions in which it will set, taking into account aspects as reservoir characteristics, present conditions, laboratory testings and a brief description of the facilities.

Ten Polyacrylamides of different molecular weight and in different forms (powder, broth, emulsions) and three biopolymers were tested in order to evaluate their suitability for a EOR project in Catriel Oeste oil field in Rio Neg4ro province, with very high water salinity. Screening involved: a) Resistance (RF) and Residual Resistance Factor (RRF) through fritted glass filters and viscosity measurement of solutions with different polymer concentrations, b) RF and RRF in actual pay zones cores with the selected polymers, c) ageing test at reservoir temperature, d) and oil recovery flood tests with final selected poliacrylamide. Laboratory tests allowed a suitable Polyacrylamide to be selected and an optimal concentration of the solutions to be injected in the field chosen, which have been used for pilot test simulation and detailed design. RF in actual cores gave satisfactory results.

Canada’s oil sands deposits in northern Alberta are estimated to contain more than 1.35 trillion barrels (~215 billion m3) of bitumen. Such a large resource base constitutes the world’s second largest oil reserves (behind only Saudi Arabia’s), even allowing for (relatively) low recovery factors. In-situ recovery technologies for these deposits, in view of the extremely viscous bitumen typically existing in them, commonly require thermal heating and/or solvent dilution to mobilize the bitumen and enable it to be produced. SAGD and CSS are currently two technologies accounting for the bulk of in-situ bitumen production in Canada.The SAGD process, utilizing two long parallel horizontal wells (upper well for steam injection, lower well for production), involves typically three sequential stages: Start-Up (Circulation), (proper) SAGD, and Wind-Down (or Blow-Down). In the Start-Up stage, steam is circulated through the two horizontal wellbores for sufficient time duration to create communication between them, prior to converting to SAGD operation. During this stage, complex heat and mass transfer phenomena occur in counter-current flow in the tubing and annulus (or tubing), and between the wells and adjacent reservoir. This paper first reviews briefly the common approaches currently utilized to model the Start-Up stage for a SAGD well pair. Next, it presents simulation results of transient steam-liquid flow inside SAGD wells, and temperature changes at the inter-wells midpoint reservoir, for a case typical of Athabasca SAGD project. Discussion – based on the distribution of steam quality, pressure and temperature losses along the axial well length – is provided, as is the estimation of the duration for effective SAGD circulation for the cited example.

Summary This paper presents experimental work that quantifies the effect of water-alternating-gas (WAG) variables on the immiscible CO2 flooding process for moderately viscous heavy oils. The results may be used to determine such parameters as total CO2-slug size, WAG ratio, and number of WAG slugs. Analysis of the relative efficiency of each WAG slug is discussed.

This study provides a quantitative analysis of the effects of neglecting the quadratic-gradient term in solving the diffusion equation governing the transient pressure distribution during high pressure-gradient injection of compressible liquids in porous media. Mathematical solutions of the two-dimensional cylindrical-symmetry nonlinear diffusion equation are derived by using the Laplace transform. A fully penetrating well bore in a homogeneous and isotropic porous medium is considered. The analysis accounts for well bore storage and incorporates a wide range of boundary conditions. Analytical early- and late-time solutions are also presented for some cases. Quantitative deviations from existing linear solutions are related to a dimensionless group, α, which is proportional to the fluid compressibility; the higher the magnitude of α, greater is the deviation of the nonlinear solutions from the linear ones. The linear pressure and rate solutions are generally within 0.5% of the corresponding nonlinear solutions for the constant pressure inner boundary. However, for the constant discharge- rate condition, the error may be as high as 10% (within the ranges of a and dimensionless radius and time considered). The error may be even higher for higher injection rates in flow systems with smaller transmissivity.

This study presents new analytical pressure solutions for high pressure-gradient flow of a single-phase, slightly compressible fluid under transient conditions. A nonlinear partial differential equation is generally used to describe the pressure behavior during such flows through porous media. The nonlinearity of this equation arises from the presence of the quadratic pressure-gradient term in the diffusion equation. In order to obtain a standard linear diffusion equation so that closed-form analytical solutions can be developed, the original nonlinear equation has traditionally been linearized by assuming the pressure gradient to be small throughout the reservoir at all times. However, during certain operations such as hydraulic-fracturing, high-drawdown flows, slug testing, large-pressure pulse testing, etc., the assumpution of a small pressure gradient may not be justified and the nonlinear pressure-gradient term must be taken into account. Moreover, in an age of increased sophistication of reservoir flow analysis and prediction methods and improved resolution of pressure-measurement devices, the effects of the quadratic pressure-gradient term on the transient pressure behavior must be understood quantitatively. In this paper, analytical dimensionless pressure solutions of the nonlinear diffusion equation are derived by using the Laplace transform. Constant-rate and constant-pressure inner boundary conditions and infinite, closed and constant-pressure outer boundary conditions have been considered. For the constant-rate inner boundary condition, solutions are presented for both injection and production problems by taking into account the presence of wellbore storage. Deviations from existing linear solutions are identified and are related to a dimensionless group, α, which is proportional to the fluid compressibility. It is shown that for constant-rate inner boundary condition, and infinite or constant-pressure outer boundary conditions, the linear pressure solutions are within 5% of the corresponding nonlinear solutions for magnitudes of α less than 0.01 (within the dimensionless time range considered). However, for a closed outer boundary, the wellbore pressure predicted by the linear solution may be significantly smaller than that predicted by the nonlinear solution at large times. Analytical steady- and pseudosteady-state solutions are also presented and compared with the corresponding linear solutions. It has been shown, with examples, that significant errors may be incurred by using the linear pressure solutions in some cases.

This research addresses the problem of waterflooding a medium-gravity of oil-bearing formation with a water leg, and offers recommendations for process selection. In many reservoirs the presence of a bottom-water zone results in a very poor areal and vertical sweep efficiencies. However, waterflooding still remains the most widely used oil-recovery technique for these reservoirs. Waterflood performance in these reservoirs can be improved greatly with effective methods of partially plugging the bottom-water zone. One such method is the use of CO 2 -activated silica gel as a blocking agent in the presence of a bottom-water zone. Thirteen large-model experiments were conducted using silica gel, to study the effect of oil-to-water zone permeability contrast and thickness ratio, oil viscosity, and CO 2 injection. A qualitative comparison is made to show the relative merit of CO 2 -activated silica gel injection among other mobility control agents. Several runs were conducted to study silica gel rheology both in presence and in absence of CO 2 .

An appraisal is presented for four different methods that are usually incorporated in thermal simulators to estimate the rate of heat loss to surroundings. The methods are the analytical solution using a superposition theorem, the analytical solution using a numerical approximation to the convolution integral, the semi-analytical solution, and the numerical solution. This appraisal includes expressing the equations in a form that can be incorporated into a fully implicit simulator, computer programming complexity, and the computer CPU time and memory storage requirements. A steam flood problem is used for the comparison, and the gas recovery, oil recovery, and heat loss performances for a reservoir in one and two dimensions are presented.

In-situ combustion and its modified forms (see Donaldson et al., 1989, p. 401) continue to be an important oil recovery process. The applicability of in-situ combustion to a wide range of reservoirs, and the recent advantages, show that this process has unique advantages (and disadvantages). Laboratory studies of in-situ combustion are hampered by the lack of suitable scaling criteria for the design of experiments. Apart from that, the experiments are usually labor-intensive and costly. This paper provides useful guidelines for the design of such experiments, and also discusses the laboratory methods currently used. The general problem of in-situ combustion in three-dimensional systems is formulated, with attention to reaction kinetics and non-equilibrium phenomena. Appropriate boundary conditions, both for field and laboratory, are stated. Next, the partial differential equations are used to derive a set of scaling criteria. A number of alternative schemes are considered in this regard. Suggestions are offered concerning the use of various options for experimental design. The scaling criteria derived are used to examine the validity of results derived from “fire tube tests”, which are widely used to obtain basic information on the combustion behavior of crude oils. It is shown that among the parameters measured in such experiments, only a few have validity. Results of laboratory fire tube tests of wet combustion can be misleading.

Summary Immiscible CO2 floods with alternating water injection are promising for heavy-oil formations ill-suited for thermal treatment. This investigation uses scaled models to show that a 20% PV slug of CO2 can recover 5 to 50% of the oil in place (OIP), depending on the operating conditions. The CO2 requirement is small, < 100 std m3/stock-tank m3.

Summary An experimental study of Athabasca bitumen/water relative permeabilities revealed little or no temperature effect on the relative permeabilities to water and bitumen over a range of 100 to 250°C [212 to 482°F]. Comparable results were obtained with both steady- and unsteady-state relative permeability measuring techniques. It was determined that the oil-phase relative permeability curve was convex. Measured curves were also compared with those obtained by history matching.

The single-phase, multidimensional flow equation for a reservoir block was derived in Chapter 2 . In Chapter 3 , this flow equation was rewritten using CVFD terminology for a reservoir block identified by engineering notation or block order. Chapters 4 and 5 presented the treatment of blocks that fall on reservoir boundaries using fictitious wells. In Chapter 6 , the wellblock production rate equation was derived for various well operating conditions. In this chapter, the single-phase, multidimensional flow equation that incorporates the wellblock production rate and boundary conditions is presented for various fluids, including incompressible, slightly compressible, and compressible fluids. These fluids differ from each other by the pressure dependence of their densities, formation volume factors (FVFs), and viscosities. The presentation includes the flow equation for an incompressible system (rock and fluid) and the explicit, implicit, and Crank-Nicolson equations for slightly compressible and compressible fluids. The flow equations for block-centered grids and point-distributed grids have the same general form. The differences between the two grid systems lie in the construction of the grid, the treatment of boundary conditions, and the treatment of the wellblock production rate as was discussed in Chapters 4-6 Chapter 4 Chapter 5 Chapter 6 . The presentation in this chapter uses CVFD terminology to express the flow equation in a multidimensional domain.

Abstract Many light and medium gravity oil reservoirs have an underlying contiguous water zone, in communication with the oil zone. As a result, a conventional waterflood is often unsuccessful because the injected water tends to channel into the more conductive bottom water layer. The research results discussed here show that modified waterfloods of such reservoirs may still be economically viable. Experiments were carried out in a three-dimensional model, employing a number of techniques, including horizontal wells. The flooding fluids consisted of polymer solutions and emulsions. The most successful strategy was to use a 10% quality oilin- water emulsion as a blocking agent, and a polymer solution as the mobility control fluid. Such a combination yielded oil recoveries approaching 70%, as compared to 50% for a conventional waterflood, for equally thick oil and water layers. The experimental results were correlated by means of a threezone analytical model allowing for crossflow between oil and water layers, which is useful for predicting the performance of such floods. Experiments utilizing horizontal injector-producer pairs for conventional waterfloods in the presence of a water leg, as well as floods utilizing polymers and emulsions showed only limited gains over vertical well pairs. Guidelines are offered for the choice of well and fluid combinations for successful floods. Introduction Waterflooding is a relatively inexpensive secondary recovery method that is used widely in the petroleum industry. In the provinces of Alberta and Saskatchewan a number of light and moderately heavy oil reservoirs contain a high water saturation zone in communication with the oil zone. Under conventional waterflood such reservoirs have been observed to show poor performance. The major reason for this is an insufficient and incomplete sweep of the reservoir by the injected water, which tends to move to the producing wells through the more permeable portions of the reservoir. This results in low recovery. Several laboratory model studies have been undertaken to investigate the effect of various parameters on oil recovery in bottom water reservoirs(1–8). High water cuts and rapidly decreasing oil rates early in the production life of such reservoirs have, in many instances, prompted their suspension or abandonment at very low levels of recovery(2). Mobility ratio is perhaps the single most important parameter in waterflooding bottom water reservoirs. A number of flooding fluids have been used to control mobility ratio. This paper examines effective techniques to waterflood bottom water reservoirs using polymer and emulsion as mobility control and/or blocking agents. The effect of vertical and horizontal injectors and different combinations were also investigated. Experimental Set-up and Procedure A diagram of the experimental apparatus is shown in Figure 1. The apparatus is made up of two constant rate pumps and a specially- designed aluminum core holder with a rectangular crosssection. The inside dimensions of the core holder were 5.08 cm (2.0 in.) wide, 7.62 cm (3.0 in.) deep and 122 cm (48 in.) long. Two pumps were used for simultaneous injection of two different fluids to simulate a vertical displacement front. The injection well was specially designed to allow the simultaneous injection of two different fluids.

Abstract Nearly 20 years of research and field testing has resulted in the development of Hydratherm ™'s hybrid drilling system, which uses ultra-high pressure (UHP) drilling fluid jets and/or a variable thermal spallation gas jet. The gas jet subjects the host rock to pulsed heat fluxes at temperatures ranging from 200 °CDATA[C to 1,100 °CDATA[C, producing thermal expansion and strength reduction of the rock-forming minerals. The UHP jets then quench, cut and erode the rock momentarily after heating. The combined mechanisms enable ultra-fast rock penetration (20 - 50 m/hr in hard rock) by means of spallation, erosion, fracturing, chipping and cutting. This technology should bring about exciting developments in heavy oil recovery, tar sand and oil shale exploitation, as well as having wider applications in mining, tunnelling and geothermal energy recovery ("HDR heat mining"). Introduction When polycrystalline rock is heated rapidly, the outer surface expands first and thin flakes or chips are shed due to tensional stress. These are known as spalls, and the process as spallation. The process has been adapted as a drilling technique, and spallation drilling systems have been in common use for over 50 years in mining and quarry work. All have used air or oxygen and fuel, with water being used for cooling purposes only. Spallation systems offer a number of advantages over rotary drilling systems, not the least of which is that penetration rates in "hard" rocks can be extremely rapid. Because the burner (drill) head does not actually contact the rock face, wear on the equipment is kept to a minimum. As the drill string does not rotate, there is no torsional stress, further reducing wear and also the tendency of holes to wander off course. Flame jet spallation burners have already been developed to the extent whereby one was used to make a 335 m (1,100 ft.) hole at Conway, New Hampshire, USA(1). However, these apparently ideal drilling systems do not work in all rock types, but only in those which are able to sustain a rapid build-up of heat without undergoing partial melting. In practical terms, this ends to be those rocks which have a high quartz content. Some rocks are almost unspallable. It is primarily this limitation which has meant that spallation systems have not been adapted for soft rock drilling work in sedimentary basins. There are also considerable practical difficulties to supplying fuel and oxygen to a burner head operating at depth. The search for a solution to these problems has resulted in the drilling systems described in this paper. It is known that low temperature spallation is more efficient than high temperature spallation in rocks with low brittle-to-ductile transformation temperatures (e.g., certain limestones)(2). Therefore, a means of controlling the thermal flux from the spallation head is essential if such rocks are to be cut. The chosen solution was to design a system that could supply water to the rock face whilst simultaneously delivering fuel and air to the burner head. This is done at ultra-high pressure so as to impose another destructive mechanism on the rock.

Abstract For complex petroleum recovery processes, an experimental investigation isusually performed with a numerical simulation to study the recoverymechanism(s). In this paper, both physical and numerical simulations of thesteam assisted gravity drainage (SAGD) process were performed. One of theobjectives of the numerical investigation was to determine the match betweenumerical results with data generated from scaled model experiments. The Computer Modelling Group's (CMG) STARS? thermal simulator was used. Resultsfrom the numerical simulation were found to be in reasonable agreement withthose obtained from the experiments for oil production rates, and cumulativeoil production. In addition, the steam chamber volume and temperaturedistribution were also examined. ffects of different parameters, such as steaminjection pressure, vertical separation between injection and production wells, nd reservoir thickness, on the performance of the SAGD process ereinvestigated. They were observed to have the same effects on both experimentaland numerical results. The numerical simulator was also used to study theinfluence of rock and fluid properties, such as oil viscosity, permeability, porosity, and the mount of heat loss from the reservoir to thesurroundings. Introduction The steam assisted gravity drainage (SAGD) process was developed by Butler(1), and is illustrated in Figure 1. It has been applied inseveral projects, including the Underground Test Facility (UTF) and has shownpromise of achieving high recovery (more than 50 % of OOIP in some cases). Many experimental and numerical studies of the SAGD process have been carriedout over the last ten years, on different aspects of the process. One of therecent numerical studies was presented by Chow and Butler(2). Theyfocused on history matching the oil recovery and the steam temperatureinterface position with those observed in the SAGD experiments by Chung and Butler(3). In the present study, numerical history matching of the experimental data, suchas the oil production and the steam chamber temperature contours [Sasaki etal.(4)] is the main focus. Furthermore, time to establish initialcommunication between the two steam injection and production wells (steambreakthrough time) was investigated. The physical and operational conditions inthe experimental study were different, compared to those used in Chung and Butler's experiments(3). They included a pressure drop of?Pi = 20 kPa, permeability of k =142 D; no pre-heating was employed.The experiments were configured to examine phenomena associated with the risingchamber. More details are provided in the following, for both experimentalinvestigation and numerical simulation. Description of the Experimental Model Several 2D visual, scaled physical models were used in the experiments. Theywere designed to represent a vertical section of a heavy oil reservoir. Themodels had sidewalls of acrylic resin (of 20 mm in thickness).

Abstract Horizontal wells have been shown to be successful in improving oil recovery for marginal heavy oil reservoirs in Saskatchewan and Alberta. One commonly encountered problem in recovery operations for these poorly consolidated reservoirs is the production of sand and fines into the horizontal wellbore, where they settle and accumulate. This paper reports the numerical modeling of gravitational deposition of sand in a horizontal well in such heavy oil reservoirs. The numerical model described in this work examines the transport process mechanistically, based on the conservation equations for the fluid phase (heavy oil) and the solid phase (sand particles). The interaction between these phases is described by empirical correlations. The equations are solved numerically to determine the concentration of sand particles and oil, and their respective pressure and velocity distributions inside the horizontal well. According to the simulation results, oil viscosity and particle size play important roles in the transport process, including controlling the gravitational settling tendency of solid particles inside the horizontal wellbore. The results provide insight into the roles different mechanisms affect the transport of sand particles; as such, they provide guidelines for production operations involving horizontal wells in poorly consolidated and unconsolidated reservoirs. Introduction The use of horizontal wells, in Saskatchewan and Alberta heavy oil reservoirs underlain with bottom-water, has been found to improve primary recovery performance prior to water coning-recovering up to 15%, in some cases, of the initial oil in place, compared with only 5% for a vertical well(1). Horizontal wells have also been successfully used for increasing steamflood recovery(2,3). Due to the unconsolidated or poorly consolidated nature of these reservoirs, solid (sand and fines) production is quite prevalent. The produced solids lead to several production problems, including sand filling up the wellbore, preventing the operation of downhole pumps and surface equipment, etc.(4) In horizontal well cases, sand production potentially poses a serious problem, as the sand could settle and accumulate inside the horizontal wellbore. This settlement and accumulation of sand particles could give rise to reduced cross-sectional areas of the wellbore open to flow. The study reported in this paper examines, using numerical simulation, the gravitational deposition of sand particles inside a horizontal wellbore. A brief survey of the relevant literature is given in the following. Solid-liquid multiphase flows are usually very complex, due to the large number of variables involved in the transport processes, and typically poorly understood interaction between the variables. There have been many experimental investigations of these (and other) flow processes, particularly focused on the deposition of the solid particles. Many of the earliest investigations of solid liquid flows focused on the settling tendency of solid particles. Richardson and Zaki(5) experimentally determined that the falling velocity of a suspension relative to a horizontal plane was equal to the upward velocity of the fluid required to maintain a suspension at the same concentration. For different flow regimes (i.e., Reynolds numbers), separate correlations were developed (from experimental data) for the exponent which corresponds to the slope of log-log plot straight lines between suspension falling velocities and suspension porosities.

Abstract This paper presents results of phase behaviour calculations and compositional simulation of asphaltene precipitation in reservoirs. For phase behaviour calculations, the precipitated asphaltene is represented by a pure solid while the oil and gas phases are modelled with an Equation of State (EOS). Compositional simulation of the dynamics of asphaltene precipitation in porous media includes the flow of suspended solid in the oil phase, deposition of solid through adsorption and entrapment, and plugging. Calculations of asphaltene precipitation for a North Sea oil with hydrocarbon gas, for a Canadian crude with CO2, and for a heavy oil with propane are described. The results are in agreement with laboratory experiments and field observations. Introduction Asphaltene precipitation from reservoir fluids during oil production is a serious problem because it can result in plugging of the formation, wellbore and production facilities. Asphaltene precipitation can occur during primary depletion of highly undersaturated reservoirs or during hydrocarbon gas or CO2 injection for improved oil recovery (IOR). The injection of hydrocarbon gases or CO2 for IOR promotes asphaltene precipitation. Numerous field reports and laboratory studies on this aspect have been published1–8. Precipitation can occur anywhere in the reservoir, although it manifests itself frequently at the production wellbore at solvent breakthrough. Asphaltene precipitation may also occur during solvent injection into heavy oil reservoirs9. Butler and Mokrys10,11 proposed an in situ solvent extraction process for heavy oils and tar sands called VAPEX. This process uses two horizontal wells (one injector and one producer). The injection of solvent (e.g. propane) creates a solvent chamber where oil is mobilized and drained toward the producer. In addition to the mobilization process, the solvent may also induce asphaltene precipitation, which provides an in situ upgrading of the oil. The Asphaltene Precipitation Envelope (APE) bounds the region where precipitation occurs12,13. In Refs. 12 and 13, the APE's are referred to as Asphaltene Deposition Envelopes (ADE). In this paper, the term "precipitation" refers to the formation of the asphaltene precipitate as a result of thermodynamic equilibrium, and "deposition" refers to the settling of the precipitated asphaltene onto the rock surface in a porous medium. The onset conditions correspond to points on the APE. Within the APE, the amount of precipitated asphaltene increases as pressure decreases from the upper onset pressure to the saturation pressure of the oil. The precipitation reaches a maximum value at the saturation pressure, and decreases as pressure decreases below the saturation pressure. Inside the reservoir, after precipitation has occurred, the asphaltene precipitate can remain in suspension and flow within the oil phase, or can deposit onto the rock surface. The main deposition mechanisms are adsorption and mechanical entrapment. The deposited asphaltene may cause plugging of the formation and alteration of rock wettability (from water-wet to oil-wet). Many thermodynamic models that describe the phase behaviour of asphaltene precipitation have been reported in the literature. These include the use of a liquid solubility model2, a thermodynamic colloidal model14, a thermodynamic micellization model15, a colloidal activity coefficient model16, a variation of a model for wax17,18, or a pure solid model19–21. Nghiem et al.20,21 also describe the incorporation of the pure solid model into an EOS compositional simulator. This paper focusses on the phase behaviour modelling and compositional simulation of asphaltene precipitation in gas injection process for IOR using a solid model for the asphaltene precipitate. Calculations are performed for three typical IOR process: a North Sea oil with hydrocarbon gas injection, the Weyburn oil with CO2 injection, and the Lindbergh heavy oil with propane injection. These represent examples of the three main solvent IOR processes where asphaltene precipitation normally occurs.

Many heavy oil and oil sand reservoirs are in communication with water sand(s). Depending on the density (°API gravity) of oil, the water sand could lie above or below the oil zone. Steamflooding a heavy oil or oil sand reservoir with a contiguous water sand (water which may lie below or above the oil-bearing zone) is risky due to the possibility of short circuiting the steam chamber. The Steam Assisted Gravity Drainage (SAGD) process was first tested at the Underground Test Facility (UTF) in Fort McMurray, Alberta. The successful application of this process to Athabasca-type oil sands has extended its application to other heavy oil and oil sands reservoirs. To date, the application of this process to a variety of different reservoirs has shown mixed results due to a variety of reasons. In our opnion, the success of these projects depends on: 1) accurate reservoir description, 2) efficient utilization of heat injected into the reservoir, 3) understanding displacement mechanism, 4) understanding of geomechanics (the interaction between the fluids and the reservoir at elevated temperatures and pressure), and 5) overcoming various operational constraints. This paper looks at how the SAGD process is affected by the presence of water sand, and determines how heat is distributed in these reservoirs. Results of this numerical simulation study show a relationship between ultimate recovery, heat accumulated in the reservoir and the thickness of the water sand (bottom or top water). For the base case run, an average rate of 80 m3/d was maintained for 1400 days before it started to decline. Ultimate recovery was approximately 70% of the OOIP after 9 years of steam injection, and the cumulative OSR was 0.3 m3/m3 (CWE). The presence of a bottom water sand has a lesser impact on recovery than the case where an overlying water sand is present. As the thickness of the water sand increases, the recovery efficiency decreases. Increasing the areal coverage of the bottom water sand resulted in slightly reduced recovery as compared with the confined bottom water sand. On the other hand, increasing the areal coverage of the overlying water sand, that is 9m thick, severely reduced the recovery efficiency of the process as heat is diverted (or channeled) into the "thief" zone. The oil steam ratio (OSR) in this run was below 0.15 m3/ m3 (CWE) after 400 days of injection. When a bottom water layer is present, the BHFP (bottom hole flowing pressure) of the horizontal producer could be operated at or above the pressure of the aquifer to prevent water coning and hence only effecting the heat source slightly.

Summary Experiments on initial stages of the steam-assisted gravity drainage (SAGD) process were carried out, using two-dimensional (2D) scaled reservoir models, to investigate production process and performance. Expansion of the initial steam chamber, its shape and area, and its temperature distributions were visualized with video and thermal-video pictures. The relationship between isotherms and steam-chamber interface was investigated to study the drainage mechanism. Temperature at the expanding steam-chamber interface was observed to remain nearly constant at close to 80°C. The effect of vertical spacing between the two horizontal wells on oil recovery was also investigated. For the Conventional SAGD case, oil production rate increased with increasing vertical spacing between the wells; however, the lead time for the gravity drainage to initiate oil production became longer. The results suggest that vertical spacing between the wells can be used as a governing factor to evaluate production rate and lead time in the initial stage of the SAGD process. Based on these experimental results, the SAGD process was modified; the lower production well was intermittently stimulated by steam injection, in conjunction with continuous steam injection in the upper horizontal injector. With the modified process (named SAGD-ISSLW), the time to generate near-breakthrough conditions between two wells was shortened, and oil production was enhanced at the rising chamber stage compared with that of the Conventional SAGD process.

Abstract Well test analyses are normally performed using a combination of type-curve and semi-log methods for determining reservoir rock properties such as permeability (transmissivity) or near-wellbore damage. Unfortunately, calculated values for these properties can vary substantially between the two methods. Conducting a history match can often eliminate ambiguity but it fails to identify the best answer from multiple solutions. A practical approach for improving reservoir characterization is introduced in this paper which allows a unique solution to be found for two or more well test analysis methods. The technique couples the multiple solution parameters to derive a testing criterion for the unique solution, i.e., two equations are combined into one with the single formulation being used to determine whether the analysed data points meet certain requirements simultaneously between the two or more solutions. It is assumed that initial boundary conditions used in deriving the separate, method-dependent solutions are identical or very similar. Two field situations are presented, one from a high transmissivity groundwater flow (water source) and the other from a low permeability oil sands reservoir. The cases, which are representative of a wide range of natural reservoir systems, serve to demonstrate both the universality of the new integrated method and the actual change from singular results. For example, values for transmissivity using two different analysis methods varied by 20%, but reanalysing the data with the composite technique reduced the difference to less than 5%. Also, a previously reported value of formation compressibility was changed by 100% after determining a more accurate value for permeability. Introduction A new, practical approach to well test analysis is presented for improving the confidence in, and the accuracy of, reservoir properties generated from such tests. Whether a geologist is investigating a fall-off well test from a permeable, confined aquifer to estimate water supply, or an engineer is studying a production buildup test from a 20-year old producing oil well to identify any formation damage, the problems encountered during analysis are very similar. Standard practice involves performing at least two types of analyses:type-curve fitting on log-log or semi-log paper and,semi-log straight line plots. A comparison of the values for transmissivity (hydrogeological term) or permeability (petroleum engineering term) from each analysis is normally done to reduce the estimates to what is thought to be the best answer. The process outlined below is intended to give a generalized method for coupling two or more analytical techniques so that only one answer is feasible, while the requirements of drawing proper slopes or curve matching are still met. The more unique the answer, the greater the confidence in using the values for formation and economic evaluations. The technique used to essentially lock analysis methods together is described by example rather than as a step-wise procedure, the reason being that each set of analysis pairs, or groups, usually provides a slightly different or even unique way to obtain the correct solution. For instance, analyses could concentrate on time intercepts rather than pressure match points or slopes.

Emulsions play more and more important role in the oil recovery as they are found to occur in most enhanced oil recovery processes and are involved in certain modes of crude oil transportation. Furthermore, they can also be used in secondary recovery as blocking agents to improve waterflooding performance in layered reservoirs or under bottom-water conditions. However, there is still a lack of detailed understanding of the mechanisms involved during the displacement process. Therefore, there is a need for understanding the physics controlling the flow of an emulsion in a porous medium. However, very little research has been carried out in the area of the flow mechanics of emulsions in porous media. Additionally, emulsion rheology and drop capture were investigated separately for certain conditions. These conditions restrict the model to specific applications. This leads to the question of how emulsion transport occurs in a porous medium in the case where emulsion drop size and the pore size are comparable, which is often the case. Therefore, the present study was carried out to observe the physical mechanisms that occurred when a stable emulsion flows in a porous medium for the system of comparable drop and pore sizes. Particularly, emulsion rheologies and droplet captures for both caustic and surfactant emulsions flowing through Berea sandstone and Ottawa sand packs were investigated comprehensively. The results show that the change in emulsion rheology in a porous medium has an overall trend similar to that in a viscometer for the shear rates of interest. Furthermore, the emulsion droplets were found to be captured according to a filtration process.

Abstract This paper describes the incorporation of an asphaltene deposition and plugging model in an Equation-of-State (EOS) compositional simulator. The precipitated asphaltene is represented as a pure solid. It is shown that this representation provides an efficient and satisfactory method for modelling the phase behavior of asphaltene, in both gas injection and pressure depletion processes. The precipitated asphaltene can deposit onto the rock surface through an adsorption process, or flow as a suspended solid in the oil phase. Compositional simulation of a typical gas injection core displacement and of a radial single-well primary depletion show that important phenomena and observations reported in the literature were reproduced adequately. P. 129

Horizontal wells may offer advantages for EOR processes, in particular, miscible and micellar flooding. A horizontal injector-horizontal producer combination, under idealized conditions, would lead to considerably reduced dispersion as compared to vertical well systems. The fluid velocity is approximately constant in such a system, as opposed to that in radial flow. This simplified picture is complicated by uneven flow along the length of a horizontal injector as a result of pressure drop. Development of miscible and micellar processes using horizontal well pairs is described. A simple computational scheme was developed to examine the limitations of horizontal wells in such applications. Examples of laboratory floods of both types are shown to demonstrate the response in comparison to the response in linear porous media. It is concluded that the advantages of horizontal well pairs over vertical pairs are limited. In particular, where there are existing horizontal and vertical wells, the judicious choice of injectors and producers is important.

Abstract A comprehensive cyclic steam stimulation simulation study for a typical Canadian heavy oil reservoir using an analytical model which considers fracturing at the wellbore has been conducted. It is concluded that several factors are involved for successful oil recovery. The results are based on a single well operation and the process becomes more complex as well interference becomes more pronounced. p. 457

The answer depends on what you call "Steam-assisted Gravity Drainage" or SAGD. In its original, pristine form, it may be the ne plus ultra of the entire repertoire of the EOR methods. In the current usage, just about any field project involving steam injection and a horizontal well, or two, is called "SAGD." Furthermore, from the published literature one gets the impression that the application of SAGD is more the rule than the exception. This would naturally lead to misapplications of the SAGD process, with less than optimal results. Our purpose in this article is to show what the original concept is, what additional factors may distort it, and what are some of the limitations of the process as applied. We will not discuss variations of SAGD, such as Enhanced SAGD and Single Well SAGD. Gravity flow and segregation are an integral part of all oil recovery processes. The role of gravity in steam injection processes was first recognized by Doscher(1) for California reservoirs, typically depleted (-0.5 MPa), with high vertical permeability and gas saturations at the top. Recently, Vogel(2) provided a lucid comparison of drive and gravity, in the context of such reservoirs. FIGURE 1: Conceptual diagram of the steam-assisted gravity drainage process. (Courtsey R.M. Butler(6)). Illustrations available in full paper. The Original Concept Figure 1 illustrates the original SAGD concept(3). Two horizontal wells, an injector above a producer, are drilled in the lower part of a formation. Both wells are at first heated by means of steam circulation. When communication is established between the two, bitumen and condensate drain along the sides of the "steam chamber." The rise of steam and the downward flow of oil and condensate are unsteady state processes. However, once the steam chamber is formed, the pressure (and so the temperature) in the chamber remain constant, with steamflood residual oil saturation in the chamber. The sideways growth of the chamber is responsible for oil production. Details have been given in several papers (in particular, see Butler(4, 5). Two definitions of SAGD are worth mentioning: "In the Steam-assisted Gravity Drainage (SAGD) process, heated oil drains from around growing steam chambers, driven by gravity to lower horizontal wells. "Butler(6) "SAGD is counter-current override, where oil moves in a direction opposite to that of steam front advance. "Edmunds(7) Gravity provides the drive in the processes described above, otherwise the processes are quite different. Whereas in the first case steam is the only flowing phase inside the steam chamber, in the second, countercurrent flow of steam, oil and steam condensate occurs-something like the segregation drive in conventional oil recovery. Edmund's description is closer to the observations in numerical simulations. In an earlier paper, Edmunds, Haston, and Best(8) identified two types of drainage processes: ceiling drainage nd slope drainage. Butler developed the flow equation for the above concept, as given in Reference (3), as well in previous publications in somewhat different forms. The key variables are: steam chamber height, permeability to oil, displaceable oil saturation, and oil viscosity at steam temperature.

Abstract Horizontal wells have been shown to be successful in improving oil recovery for marginal heavy oil reservoirs in Saskatchewan and Alberta. One commonly encountered problem in recovery operations for these unconsolidated reservoirs is the production of sand and fines. The settling and accumulation of the solid particles inside the horizontal wellbore represents a serious problem, with the horizontal well becoming partially plugged being a real possibility. This study investigates this problem, with focus on determining the roles played by different flow parameters on the settling and transport process. The physical model described in this work examines the transport process mechanistically. Conservation equations for the solid phase (sand particles) and the fluid phase (oil) are formulated, with the interaction between the phases described by empirical correlations. The oil is assumed to be a Newtonian fluid, and the sand particles are assumed to be spherical in shape and uniform in size. The system of equations is solved numerically to determine the distribution of sand particles and oil, and the respective pressure and velocity distributions as a result of the presence of a constriction inside the horizontal well. According to the simulation results, oil viscosity and particle size play important roles in the transport process, including controlling the gravitational settling tendency of solid particles inside the horizontal wellbore. The results provide insight into the mechanisms involved in the transport process; as such, they provide guidelines for production operations involving horizontal wells in unconsolidated and poorly consolidated reservoirs. Introduction One of the most common applications of horizontal well technology in Canada is to recover oil from heavy oil reservoirs in Saskatchewan and Alberta. In heavy oil reservoirs underlain with bottom-water, the use of horizontal wells has been found to improve primary recovery performance prior to water coning - recovering up to 15% of the initial oil in place (in shorter time, also), compared with only 5% for a vertical well. Horizontal wells have also been successfully used for increasing steamflood recovery. However, recovery operations in these heavy oil reservoirs are usually susceptible to sand production due to their unconsolidated nature. The produced sand could give rise to production problems. as the sand fill up the wellbore, prevent the operations of downhole pumps, etc. In the case of horizontal wells, sand production potentially poses an even more serious problem, due to the settlement and accumulation of sand particles at different positions along the well - leading to the reduction of the cross-sectional area of the wellbore open to flow (Figure 1). The ultimate effect of sand deposition could be the partitioning of the horizontal well into several segments, leading to a loss of production and a negation of the principal advantage of horizontal wells (large contact area with the reservoir). The study reported here investigates this problem. Specifically the study examines, through numerical simulation, the transport and distribution of sand particles, pressure, and velocity distributions in a horizontal well. A special feature of the physical model is the presence of a constriction inside the horizontal well. Solid-liquid flow encompasses many different areas of science and engineering, including the transport of colloids in rain water, sediment transport in river streams, slurry pipeline transportation, drill cuttings removal, transport of proppants in hydraulically fractured wells, etc. The large number of independent variables involved in these transport processes, coupled with the complex interaction between the variables have precluded comprehensive analytical studies of these processes mechanistically. Instead, many experimental studies have been carried out over the years. P. 471^

Abstract Canada's heavy oil and oil sands deposits are estimated to contain as much oil as the conventional oil resources of the entire world. Heavy oil deposits, in particular those in southwestern Saskatchewan and southeastern Alberta, represent an attractive target for exploitation as the in-place heavy oils are mobile under reservoir conditions. These reservoirs typically have good porosity, high permeability (1–5 darcies), high initial oil saturation >65%), and the oil viscosity ranges from 1000 to 1500 cp; but the pay thickness is between 3–10 metres and often underlain by bottom water zone ("bottom water"). Primary recovery in these reservoirs typically amounts to less than 5% of the initial oil in place (IOIP). In a few cases, where the conditions are more favorable, use of horizontal wells has increased primary recovery to 15-20% prior to water coning. This still leaves up to 80% of the oil in place unrecovered. Using a scaled physical model of the Aberfeldy reservoir (Saskatchewan), steamflood experiments were performed to investigate steamflood recovery performance using horizontal injection and production wells. This paper reports results of analyses made for two types of experiments; one was for steamflooding a homogeneous reservoir (base case run), and the other was for steamflooding a reservoir having a 20% net pay bottom water layer. Analyses include comparisons between steam zone volumes obtained experimentally and theoretically, and heat distribution (heat injected, heat loss, heat accumulated, and heat produced) during a steamflood The scale up of laboratory results to predict prototype field performance is also presented. The analytical heat loss model, based on the simultaneous solution of two heat conduction equations, showed a 3.1% difference from experimental results. Scaled-up experimental data, for the base case run (horizontal injector and producer), showed that approximately 20% of the initial oil in place (IOIP) was recovered after 0.8 PV of steam (CWE) had been injected. For a reservoir having a 20% net pay bottom water, after 0.8 PV of steam (CWE) had been injected, heat accumulated in the formation was found to be approximately 3776.6 kJ. Of this, 2000 kJ of energy was stored in the matrix, and the fluids in the reservoir contained 1776.6 kJ of energy. The increase in the oil recovery for a reservoir having 20% net-pay bottom water layer depends on how the energy contained in the fluids is managed Introduction Over 20 billion barrels of oil are contained in the marginal heavy oil reservoirs of Saskatchewan and Alberta. These reservoirs are thin (3–10 meters of pay) and often in communication with an underlying water zone. Cyclic steam stimulation and steamflooding operations using vertical wells have proven uneconomic in these reservoirs, mainly due to excessive channeling of steam. On the other hand, horizontal wells have been shown to be capable of improving steamflood recovery performance, due to their extended contact with the reservoir and their ability to improve sweep efficiency (due to a delay in steam override, and minimizing effect of heat loss to the cap/base rock). This study attempts to provide insight into the performance prediction of steamflooding a marginal heavy oil reservoir using horizontal injection and production wells, and looks at different steamflooding strategies for improving recovery. These objectives were achieved experimentally using a scaled physical model, and a visual unscaled model. P. 93^

Abstract Horizontal wells have been used successfully in Canada to recover oil from marginal heavy oil reservoirs in Saskatchewan and Alberta. These reservoirs are often poorly consolidated; recovery operations in these reservoirs are, therefore, usually susceptible to sand production. A horizontal well could be partially blocked due to the deposition and accumulation of sand particles inside the wellbore. This study presents a mathematical treatment of the transport process of oil and sand particles inside a constricted horizontal well. The model described in this paper formulates the transport process mechanistically. Continuum assumption is made for the fluid phase (oil) as well as the solid phase (sand particles). Equations of mass and momentum conservation for the solid phase and the fluid phase are formulated. The oil is assumed to be Newtonian, and the sand particles are assumed to be spherical in shape and uniform in size. The model incorporates empirical correlations to describe the interaction between the two phases. The system of equations is solved numerically to determine the transient distribution of sand particles and oil, and their pressure and velocity distributions as a result of an expanding constriction inside the horizontal well. Numerical simulation results provided insight into the mechanisms involved in the transport process, thus enhancing the understanding of the flow of sand and oil inside a horizontal well. Introduction One of the most common applications of horizontal well technology in Canada is to recover oil from heavy oil reservoirs in Saskatchewan and Alberta. In heavy oil reservoirs underlain with bottom-water, the use of horizontal wells has been found to improve primary recovery performance prior to water coning, recovering up to 15% of the initial oil in place compared with only 5% for a vertical well(1). The recovery rate is also increased. Horizontal wells have also been successfully used for increasing steamflood recovery(2, 3). However, recovery operations in these heavy oil reservoirs are usually susceptible to sand production due to their unconsolidated nature. The produced sand could give rise to production problems, as the sand fill up the wellbore, prevent the operations of downhole pumps, etc.(4). In the case of horizontal wells, sand production potentially poses an even more serious problem, due to the settlement and accumulation of sand particles at different positions along the well, leading to the reduction of the cross-sectional area of the wellbore open to flow (Figure 1). The ultimate effect of sand deposition could be the partitioning of the horizontal well into several segments, leading to a loss of production and a negation of the principal advantage of horizontal wells (large contact area with the reservoir). The study reported here investigates this problem. Specifically the study examines, through numerical simulation, the transport and distribution of sand particles, and pressure, and velocity distributions in a horizontal well. A special feature of the model is the presence of a constriction inside the horizontal well.