Thermal Oil Recovery Processes Research Articles

Local thermal equilibrium constraints for energy transport equations for thermal oil recovery processes

The mathematical framework of reservoir thermal simulators typically relies on the assumption of local thermal equilibrium (LTE) when modeling energy transport through porous media for petroleum engineering applications, including Thermal Enhanced Oil Recovery (TEOR) processes. The LTE presupposes instantaneous exchange of energy between the injected hot fluids and the reservoir's rock and fluids. Nevertheless, it is essential to acknowledge that LTE's validity becomes questionable in specific scenarios, potentially resulting in an overestimation of oil recovery, e.g., when high fluid velocities arise. Under such conditions, the local thermal non-equilibrium (LTNE) formulation may offer a more accurate representation of the energy transport physics. In this study, we present the physical constraints that must be satisfied for the application of two distinct mathematical formulations (1) the one-equation model for the fluids and rock as a whole (LTE is assumed), and (2) the two-equation model, one equation assigned to the fluids and another one to the rock (pseudo-LTNE is assumed). Such constraints were derived by examining conductive and convective heat transport properties via the theory of the method of volume averaging, specifically applied to an oil-water-gas-rock system at the pore scale. It was found that the one-equation model requires that 18 physical constraints to be satisfied, while the pseudo-LTNE model needs to fulfill 9 physical constraints. A sensitivity analysis was conducted based on factor upon which accumulation, conduction and convection constraint equations depend, aiming to identify the conditions under which LTNE occurs within the porous medium. These influencing factors encompass the characteristic time, the Peclet number, the presence of external heat sources, the distribution of phases at the pore-scale, and the disparity between rock and fluid properties. The combinations of these factors can induce the existence of local thermal non-equilibrium. One significant property is the heat transfer coefficient in the reservoir. We recommend that the pseudo-LTNE approach is reliable as long as the rock-fluid heat transfer coefficients are at least one order of magnitude larger than the fluid-fluid heat transfer coefficients (1000−10000W/(m3K)). Contrarily, the OEM should be employed only when the heat transfer coefficients surpass a threshold value of 10000W/(m3K). When injector and producer wells are hydraulically interconnected, resulting in heightened fluid velocities, it is encouraged the use of the two-equations model. The predictability and reliability of the energy models were verified by comparison of predicted oil recovery against data from laboratory experiments. The equations presented in this study consistently demonstrate their utility in assessing the reliability of energy transport models for TEOR scenarios.

Nanotechnology Applied to Thermal Enhanced Oil Recovery Processes: A Review

The increasing demand for fossil fuels and the depleting of light crude oil in the next years generates the need to exploit heavy and unconventional crude oils. To face this challenge, the oil and gas industry has chosen the implementation of new technologies capable of improving the efficiency in the enhanced recovery oil (EOR) processes. In this context, the incorporation of nanotechnology through the development of nanoparticles and nanofluids to increase the productivity of heavy and extra-heavy crude oils has taken significant importance, mainly through thermal enhanced oil recovery (TEOR) processes. The main objective of this paper is to provide an overview of nanotechnology applied to oil recovery technologies with a focus on thermal methods, elaborating on the upgrading of the heavy and extra-heavy crude oils using nanomaterials from laboratory studies to field trial proposals. In detail, the introduction section contains general information about EOR processes, their weaknesses, and strengths, as well as an overview that promotes the application of nanotechnology. Besides, this review addresses the physicochemical properties of heavy and extra-heavy crude oils in Section 2. The interaction of nanoparticles with heavy fractions such as asphaltenes and resins, as well as the variables that can influence the adsorptive phenomenon are presented in detail in Section 3. This section also includes the effects of nanoparticles on the other relevant mechanisms in TEOR methods, such as viscosity changes, wettability alteration, and interfacial tension reduction. The catalytic effect influenced by the nanoparticles in the different thermal recovery processes is described in Sections 4, 5, 6, and 7. Finally, Sections 8 and 9 involve the description of an implementation plan of nanotechnology for the steam injection process, environmental impacts, and recent trends. Additionally, the review proposes critical stages in order to obtain a successful application of nanoparticles in thermal oil recovery processes.

Dynamic optimization of thermodynamically rigorous models of multiphase flow in porous subsurface oil reservoirs

In this paper, we consider dynamic optimization of thermal and isothermal oil recovery processes which involve multicomponent three-phase flow in porous media. We present thermodynamically rigorous models of these processes based on 1) conservation of mass and energy, and 2) phase equilibrium. The conservation equations are partial differential equations. The phase equilibrium problems that are relevant to thermal and isothermal models are called the UV and the VT flash, and they are based on the second law of thermodynamics. We formulate these phase equilibrium problems as optimization problems and the phase equilibrium conditions as the corresponding first order optimality conditions. We demonstrate that the thermal and isothermal flow models are in a semi-explicit differential-algebraic form, and we solve the dynamic optimization problems with a previously developed gradient-based algorithm implemented in C/C++. We present numerical examples of optimized thermal and isothermal oil recovery strategies and discuss the computational performance of the dynamic optimization algorithm in these examples.

Estimation of the Combustion Temperature Profile in a Romanian Oil Field

Developing and producing of the heavy crude oil involved significant economic and technological challenges. The oil industry ability to prospect and capitalize the huge world heavy oil resources both economically and environmentally friendly will be crucial in helping meet future energy needs. Thermal oil recovery is one of the three types of techniques belonging to Enhanced Oil Recovery. It is applied for increasing the cumulative of crude oil that can be produced in an oil field. One of the oldest thermal oil recovery is in-situ combustion or fireflooding applied for the first time about 100 years ago. Despite in-situ combustion has not found widespread acceptance among operators like other thermal processes (such as steam injection), analysis of the successful projects indicates that the process is applicable to a wide range of oil reservoirs, especially to heavy crude oils. An important monitoring parameter of thermal oil recovery process is represented by thermal regime especially in heavy oil fields in which a high-temperature regime must be occur as the in-situ combustion to be successful. In the paper the authors are using thermal analysis (thermogravimetric and thermodifferential analysis) for investigation of the thermal regime involved in the production process of an oil reservoir by in-situ combustion.

Investigation of the combustion characteristics of Bati Raman oil with sand

In situ combustion (ISC) is one of the thermal oil recovery processes that has been applied in a variety of reservoirs. The energy is generated within the reservoir by a series of multi-step reactions that provide energy to heat the reservoir and reduce oil viscosity. Also, the oil is upgraded in situ by burning heaviest fractions.In this study, combustion characteristics of Bati Raman crude are investigated. The Bati Raman oil field is the largest known oil field in Turkey. Ramped temperature oxidation (RTO) experiments with effluent gas analysis (EGA) are performed with oil-sand mixtures having different sand particle size. The results are analyzed using isoconversional kinetic approach, which is a model-free method, based on effluent gas analysis and temperature measurements. Effective activation energy values are estimated for the sample with two different sand particle size. Besides, for the same samples, laboratory combustion tube experiments are conducted to evaluate ignition and combustion front propagation characteristics. Asphaltene content and API gravity of the oil sample prior to experiments and produced oil are measured and compared. Results indicate that the oil is upgraded through a reduction in asphaltene content.A complete set of kinetics and combustion experiments are provided for Bati Raman oil. There are only limited number of studies in the literature to link kinetic experiments to proposed reaction models of ISC. This work presents a way to link a reaction model to isoconversional fingerprint obtained through kinetic experiments. In addition, it is shown that Bati Raman oil exhibits good combustion characteristics and it is associated with its isoconversional fingerprint.

Water content of light n‐alkanes: New measurements and cubic‐plus‐association equation of state modeling

Light hydrocarbon gases such as methane, ethane, propane, and butane or other so called gaseous solvents have been suggested as steam additives to improve bitumen recovery and energy efficiency. The water content of these gases is one of the key requirements in the simulation and design of solvent‐aided thermal heavy oil recovery processes. In this work, we present new experimental data for the water content of these gases at high temperatures (up to 493.15 K) and moderate pressures (P < 6 MPa). The experimental data was regenerated using the cubic‐plus‐association equation of state. The Soave–Redlich–Kwong equation of state is used to treat the physical interactions. The association interactions are captured using Wertheim's first‐order thermodynamic perturbation theory. A set of binary interaction parameters is proposed to calculate the water content of methane, ethane, propane, and n‐butane at the operating conditions of the thermal heavy oil and bitumen recovery processes. © 2016 American Institute of Chemical Engineers AIChE J, 63: 1384–1389, 2017

Economic optimization for operation options in thermal oil recovery process

ABSTRACTThis paper describes the uses of the Box–Behnken experimental design to optimize the factors affecting the production performance in steam-assisted gravity drainage (SAGD) operation, Peace River oil sands. The response surface methodology (RSM) was employed to search for the best designs in contour plots and response surface map. A total of 41 cases were run to optimize the parameters of operating conditions and the net present value (NPV) responses during 10 years of the simulation period. To maximize the net present value, the optimal conditions should operate at a well pattern spacing (WPS) of 78 m, a steam injection rate of 550 m3/d, an injector producer spacing (IPS) of 14 m, injection a pressure (IP) of 6,350 kPa, and a subcool of 5°C.Simulation results showed that cumulative oil for the Fast-SAGD process does not significantly increase and even NPV is the lowest among the mentioned SAGD cases. The difference of 10 kPa between steam IP and reservoir pressure is not sufficient to increase the NPV for both Fast-SAGD and SAGD operations.

Finite Element Analysis of Casing Material Behavior in Steam Injection Well Operations

Casing design is one of the most important parts of the well planning in the oil and gas industry. Various factors affecting the casing material needs to be considered by the drilling engineers. Wells partaking in thermal oil recovery processes undergo extreme temperature variation and this induces high thermal stresses in the casings. Therefore, forecasting the material behavior and checking for failure mechanisms becomes highly important. This paper uses Finite Element Methods to analyze the behavior two of the frequently used materials for casing - J55 and L80 steels. Modeling the casing and application of boundary conditions are performed through Ansys Workbench. Effect of steam injection pressure and temperature on the materials is presented in this work, indicating the possibilities of failure during heating cycle. The change in diameter of the casing body due to axial restriction is also presented. This paper aims to draw special attention towards the casing design in high temperature conditions of the well.

Characterization of water-containing reservoir oil using an EOS for steam injection processes

Experimental results in the literature indicate that the water solubility in the oleic (L) phase (xwL) can be high at reservoir conditions in thermal oil recovery processes. However, the effect of xwL on oil recovery has not been fully understood, especially for steam-assisted gravity drainage (SAGD) for in-situ bitumen recovery. This research presents a framework for reliable characterization of water/reservoir–oil mixtures for numerical simulation of steam injection processes. The Peng–Robinson equation of state (PR EOS) is used with the van der Waals mixing rules.A new correlation is developed for binary interaction parameters (BIPs) for water with n-alkanes. Unlike previously proposed BIP values, the new correlation is based on optimization of three-phase predictions for water/n-alkane binaries, including upper critical endpoints (UCEPs). In the characterization method proposed for water-containing reservoir oil, the developed correlation serves as the well-defined upper limit for BIPs of water with hydrocarbon components. A SAGD simulation case study for Athabasca bitumen shows that bitumen recovery can be substantially affected by xwL through the L-phase mobility. The characterization method developed in this research can be used with at least one measured xwL value for a reliable phase-behavior model for steam injection simulation.

Prediction of water solubility in petroleum fractions and heavy crudes using cubic-plus-association equation of state (CPA-EoS)

Knowledge of the solubility of water in hydrocarbon fluids is essential for the design, simulation, and optimization of thermal oil recovery processes. This study proposes the use of cubic-plus-association equation of state (CPA-EoS) to predict the mole fraction of water in hydrocarbon fluids with specific gravity and molecular weight as the correlating parameters. Experimental data for water solubility in petroleum fractions, heavy oils, and bitumens was represented with an absolute average relative deviation (AARD) of less than 6.8%. The binary interaction parameter between the water and hydrocarbons was determined for different crudes. The proposed model can be applied to petroleum fractions, heavy oils, and bitumens with molecular weights between 140 and 678g/mol at temperatures up to 560K, which is the practical range of many industrial applications.

Kinetic Study of Catalytic In-situ Combustion Processes in the Presence of Nanoparticles

In recent years, there has been great interest in the application of special nanoparticles on thermal oil recovery processes. In this article, based on nanotechnology, a new method for improving the performance of in-situ combustion process is presented. This work aims at studying the effect of engineered nanoparticles on the activation energy of crude oil oxidation reactions in relation to in-situ combustion processes. Similar to previous studies, three oxidation regions were observed in crude oil combustion in porous media and it was found that each particular nanoparticle has a different effect on each oxidation region. Results show a significant reduction in the activation energies of oxidation reactions, which is an indication of strong catalytic effect of nanoparticles. The catalytic efficiency of nanoparticles was found to be a function of nanoparticle type and concentration. From the results of this study, it can be pointed out that nanoparticles have the potential to be applied as an effective additive to improve in-situ combustion performance.

Steam-on-a-chip for oil recovery: the role of alkaline additives in steam assisted gravity drainage

We present a lab-on-a-chip approach to informing thermal oil recovery processes. Bitumen - a major global resource - is an extremely viscous oil which is extracted by injecting steam underground in a process known as Steam Assisted Gravity Drainage (SAGD). Here, a microfluidic network saturated with bitumen provides a physical model of the SAGD reservoir; steam is injected into the chip, and the oil recovery dynamics are visualized and quantified in real-time. The unique advantage of this approach is the pore-scale quantification of fluid phase dynamics under relevant reservoir conditions and pore sizes. High resolution is achieved by leveraging the inherent fluorescence of the native bitumen. The approach is applied to quantify the efficacy of an alkaline steam additive. With the additive, the mean characteristic size of oil-in-water emulsions formed during SAGD is reduced from 150 μm to 6 μm, and the corresponding recovery effectiveness is improved by ~50%. These results demonstrate that pore-scale process quantification enabled by lab-on-a-chip methods can improve the efficacy, and the associated carbon footprint, of energy intensive thermal oil recovery processes.

BioDiesel as Additive in High Pressure and Temperature Steam Recovery of Heavy Oil and Bitumen

Use of additives to improve the efficiency of thermal heavy oil and bitumen recovery processes has been studied extensively over the decades. Two common types of additives used in thermal applications, mainly steam assisted recovery, are solvents and surfactants. Commercial use of solvents has setbacks due to their high costs and retrieval difficulties. Cost and stability of the surfactants under reservoir operating temperature and pressure are the major concerns. We propose the use of bioDiesel such as fatty acids methyl ester as a surfactant additive reducing heavy oil/bitumen-water interfacial tension in steam assisted recovery processes. Advantages of using bioDiesel as a surfactant additive are that bioDiesel is chemically stable under the operating pressure and temperature of the reservoir, it causes no harm on bitumen fuel quality and on release water chemistry and its use is economically feasible.We conducted a series of steam assisted bitumen recovery experiments to clarify the additional recovery potential and efficiency improvement capacity of bioDiesel. High pressure steam at 1.8 MPa pressure, 205°C was used in these tests at a 900 g/h feed rate. The porous media used was a normal grade oil sands ore obtained from a surface mine operation in Northern Alberta, Canada. Oil sands ore was packed in a basket and placed in a high pressure cell. Bitumen recovery experiments were performed by spraying canola oil fatty acid methyl ester on oil sands ore at a 2 g/kg-bitumen dosage. These tests show that bitumen recovery efficiency increases over 40%. In another series of tests, tall oil fatty acids methyl ester was injected into a high pressure steam line at a 8.3 g-bioDiesel/kg-steam dosage. Because of the solubility of bioDiesel in bitumen, the effect of bioDiesel on bitumen recovery could not be accurately concluded. Vapor pressure measurements performed on canola oil and tall oil derived bioDiesel samples suggest that saturation compositions of bioDiesel in steam at 1.8 MPa pressure and 205°C are at least one order of magnitude higher than the requested bioDiesel dosages. Further tests are planned by reducing bioDiesel dosages to about 0.5 to 1.0 g-bioDiesel/kilogram-steam and by monitoring the solubility of bioDiesel in bitumen.

Comparative study of eight cubic equations of state for predicting thermodynamic properties of alkanes

AbstractPrecise descriptions of the thermodynamic properties of pure fluids require accurate definition of vapour–pressure and phase volumes as well as residual volumes, enthalpies and entropies. While carefully fitted multi‐parameter equations of state (EOS), such as Benedict–Webb–Rubin–Starling fulfil these requirements, cubic EOSs usually do not. On the other hand, cubic EOSs are widely used in the oil industry, due to their simplicity and reliability in most vapour–liquid equilibrium calculations. For thermal oil recovery processes and the natural gas industry, the choice of EOS becomes important for predicting thermodynamic properties, such as isobaric and isochoric heat capacities, sound velocity and the Joule–Thomson coefficient. In this study, eight cubic EOSs which most of them are used in commercial reservoir simulators are selected for evaluation of their capability in the prediction of second‐order derivative thermodynamic properties at different temperatures and pressures, using pure components frequently found in petroleum and natural gas mixtures. It is shown that none of the cubic EOSs could accurately predict all of the stated parameters, especially below the critical point. All EOSs failed to show the extrema in the derivative properties. However, among these equations the Yu–Lu and Schmidt–Wenzel EOSs were found to have more reliable predictions in most of the cases. © 2011 Canadian Society for Chemical Engineering

Numerical experiments on oil sands shear dilation and permeability enhancement in a multiphase thermoporoelastoplasticity framework

Oil sands exhibit substantial shear dilation during thermal oil recovery processes. Shear dilation is the result of increasing effective horizontal stresses induced by inhomogeneous thermal expansion; shear dilation is irreversible and in quartzose sands leads to porosity, permeability and compressibility increases. Hence, shear dilation has been considered a major and positive geomechanics factor in thermal enhanced oil recovery. In this paper we extend a fully-coupled thermal reservoir model in the multiphase thermoporoelastic framework to a multiphase thermoporoelastoplastic framework, in order to account for shear dilation. In a series of numerical experiments we explore how the stiffness and Poisson's ratio of overburden rocks and the initial stress state in the reservoir affect the reservoir stress path, thus directing changes in the magnitude of shear dilation, porosity change and permeability enhancement. Numerical results indicate that a stiffer overburden rock leads to a smaller magnitude of shear dilation and permeability enhancement; a smaller Poisson's ratio of the overburden rock has only a slightly positive contribution; a larger initial lateral stress ratio corresponds to a larger magnitude of shear dilation and permeability enhancement; and a larger dilation angle of oil sands leads to a larger magnitude of shear dilation and permeability enhancement.

Economic Optimization and Uncertainty Assessment of Commercial SAGD Operations

Abstract As SAGD is being increasingly used as a commercial technology to recover heavy oil and bitumen, it is essential to determine the most economical operating conditions for a SAGD operation by reservoir simulation. Furthermore, to support the decision-making process of a SAGD project, it is also important to quantitatively assess the uncertainty of its economicforecasts. In this paper, the application of global optimization, experimental design, response surface generation and Monte Carlo simulation techniques in the workflow of SAGD simulation studies were demonstrated with a real field case example. The field case is an infill SAGD project with two planned SAGD well pairs and eight existing primary production wells which have 5 years of primary production. A bottomwater zone is also present. Three major steps of the workflow are:history matching primary production data;optimizing SAGD performance; andquantifying uncertainty of the SAGD forecasts. Firstly, experimental design and DECE (Designed Exploration and Controlled Evolution) optimization methods were used to achieve a faster and better history match than the traditional manual history match. Secondly, SAGD performance was optimized by adjusting the steam injection rate and producer liquid withdrawal rate during different SAGD operation periods. Finally, experimental design and response surface generation techniques were applied to build a polynomial response surface through which the net present value (NPV) of the SAGD project is correlated with uncertain parameters and a SAGD design parameter. Monte Carlo simulation was then performed to quantify the uncertainty of SAGD forecasts in terms of cumulative probability distribution of the NPV at different values of the SAGD designparameter. The results show that the economics of this project are improved considerably through optimization. The optimum operating conditions obtained use a high initial steam rate and high production rate to develop the steam chamber. After the instantaneous steam-oil ratio reaches a certain value, both steam rate and production rate are lowered to prevent steam breakthrough to the bottomwater. The uncertainty of the project NPV was assessed, taking into consideration the uncertainties in high temperature relative permeability endpoints and the variation of the SAGD design parameter. Introduction Steam-assisted gravity drainage (SAGD) is a thermal oil recovery process which consists of pairs of two parallel horizontal wells drilled near the bottom of the pay(1). Typically, the length of the wells are between 500 and 1,000 m, the inter-well distance of the two parallel wells is between 5 and 10 m and inter-well pair spacing is between 90 and 120 m(2, 3). The top horizontal well is used to inject steam, while the bottom horizontal well is used to produce reservoir fluids. The steam injected from the top well rises into the formation, forming an expanding steam chamber around and above the injection well. The rising steam eventually loses its latent heat near the boundary of the steam chamber, heats the oil and allows it to drain to the bottom production well by gravity. Successful field tests have proven that SAGD is a viable technology for in situ recovery of heavy oil and bitumen(4–6).

An Equation-of-State Compositional In-Situ Combustion Model: A Study of Phase Behavior Sensitivity

In order to facilitate the study of reactive-compositional porous media processes we develop a virtual kinetic cell (single-cell model) as well as a virtual combustion tube (one-dimensional model). Both models are fully compositional based on an equation of state. We employ the models to study phase behavior sensitivity for in situ combustion, a thermal oil recovery process. For the one-dimensional model we first study the sensitivity to numerical discretization errors and provide grid density guidelines for proper resolution of in situ combustion behavior. A critical condition for success of in situ combustion processes is the formation and sustained propagation of a high-temperature combustion front. Using the models developed, we study the impact of phase behavior on ignition/extinction dynamics as a function of the operating conditions. We show that when operating close to ignition/extinction branches, a change of phase behavior model will shift the system from a state of ignition to a state of extinction or vice versa. For both the rigorous equation of state based and a simplified, but commonly used, K-value-based phase behavior description we identify areas of operating conditions which lead to ignition. For a particular oil we show that the simplified approach overestimates the required air injection rate for sustained front propagation by 17% compared to the equation of state-based approach.

Efficient integration of stiff kinetics with phase change detection for reactive reservoir processes

We propose the use of implicit one-step Explicit Singly Diagonal Implicit Runge–Kutta (ESDIRK) methods for integration of the stiff kinetics in reactive, compositional and thermal processes that are solved using operator-splitting type approaches. To facilitate the algorithmic development we construct a virtual kinetic cell model. The model serves both as a tool for the development and testing of tailored solvers as well as a testbed for studying the interactions between chemical kinetics and phase behavior. As case study, two chemical kinetics models with 6 and 14 components, respectively, are implemented for in situ combustion, a thermal oil recovery process. Through benchmark studies using the 14 component reaction model the new ESDIRK solvers are shown to improve computational speed when compared to the widely used multi-step BDF methods DASSL and LSODE. Phase changes are known to cause convergence problems for the integration method. We propose an algorithm for detection and location of phase changes based on discrete event system theory. Experiments show that the algorithm improves the robustness of the integration process near phase boundaries by lowering the number convergence and error test failures by more than 50% compared to direct integration without the new algorithm.

Steam and Gas Push (SAGP)-3;Recent Theoretical Developments and Laboratory Results

Abstract SAGP is a thermal oil recovery process that is similar to Steam-Assisted Gravity Drainage (SAGD) but which involves the addition of a small concentration of a non-condensable gas to the steam. This paper is a continuation of parts 1 and 2 presented at the 48th and 49th Annual Technical Meetings of the Petroleum Society. Theoretical developments and laboratory experiments continue to show significant improvements for the process as compared to SAGD. Experimental results have now been obtained with Athabasca crude oil as well as Cold Lake and Lloydminster type oils. In SAGP much of the oil displacement is caused by the flow of fingers of gas/steam rising counter-currently to the draining oil, rather than by the simple advance of a continuous steam chamber. The rising gas fingers raise the pressure in the reservoir above and this increase in pressure towards the top of the reservoir tends to push the oil down. Gas accumulates in the upper part of the reservoir and oil drains to the production well near to the bottom. The mechanism is discussed in the paper together with results from recent scaled, physical model experiments. The work demonstrates that SAGP may be expected to produce oil at rates nearly equivalent to SAGD but with much lower steam consumption. Introduction The successful applications of the Steam-Assisted Gravity Drainage (SAGD) process in the fields have provided tremendous opportunities for the development of heavy oil and bitumen resources. SAGD field projects are continuing to be constructed following the successful testing of the process at AOSTRA's Underground Test Facility (UTF) (now Northstar's Dover project). In addition to Canadian projects, this process has also been field tested in other countries(1). Most recently, the SAGD project in the Tia Juana field in Venezuela(2) is reported to produce average oil rates of 700 bpd per well pair from the first year's operation. Although SAGD is effective in producing bitumen and heavy oils, it requires a large quantity of heat to heat the whole chamber to saturated steam temperature and the heat loss to the overburden is high. The process may become uneconomic in some reservoirs such as those with thin sands, low porosity, low oil saturation, and bottom water zones. To extend the range of reservoirs that can be produced economically with SAGD technology, a new process was developed to reduce the heat loss to the overburden while maintaining high oil drainage rates. The Steam and Gas Push (SAGP) process involves the addition of a small amount of non-condensible gas, such as nitrogen or methane, to the steam. The accumulation of gas in the upper part of the chamber reduces the average temperature in the chamber and the heat loss to the overburden. As a result, the steam requirement is reduced and oil/steam ratio is improved. Both theoretical and physical model studies have been carried out at the University of Calgary with support from participants from industry, since the process was first described(3). Some mechanisms and model test results were described at the 49th ATM(4) and the 7th UNITAR International Conference on Heavy Crude and Tar Sands(5).

Numerical Investigation of SAGD Process Using a Single Horizontal Well

Abstract Recently several articles have been published regarding the innovation and field applications of the Steam-Assisted-Gravity-Drainage (SAGD) process using a single horizontal well for the recovery of heavy oil. In the process, an insulated concentric coiled tubing, inserted into the horizontal wellbore, injects high quality steam to the toe of the well. The steam condensate and reservoir fluids enter the wellbore and flow back along the annulus to the heel to be produced. There remain some arguments on whether the SAGD mechanism is working in field operations and on what oil rates can be achieved in the long run. In an attempt to answer these questions, numerical simulation studies were pursued in the present work. The studies focused on three major aspects:the possible counter-current fluid exchange pattern between the reservoir and the well;the means that could be exploited to promote the initiation of a steam chamber; andthe potential oil rates that could be expected under possible field operating conditions. The results showed that the presence of small capillary pressure near a horizontal wellbore is a physical constraint preventing counter-current exchange of steam and oil. It was also demonstrated that vertical undulation in well-profile or a certain level of formation dilation around the wellbore could potentially overcome the capillary pressure constraint and promote the initiation of a steam chamber under field operating conditions. Introduction After over 20 years of extensive laboratory studies and field trials, the concept of Steam-Assisted-Gravity-Drainage (SAGD)(1) has evolved into a commercially viable thermal oil recovery process for certain heavy oil reservoirs(2,3). In the conventional SAGD process(4), a pair of vertically stacked horizontal wells is used; in which the top well is used for steam injection and the bottom well is used for fluid production. Even with the latest drilling/completion technologies, it may still be difficult to properly place the well pair into a formation(2). In order to reduce the high cost associated with the drilling and completion of two horizontal wells, industry has sought alternative well configurations since the first field trial(5–9). One of the approaches is to utilize only one horizontal well for both steam injection and fluid production(5,8). As early as 1978, Imperial Oil conducted the pioneering horizontal well field pilot (HWP-1) to test the SAGD process(10). In the pilot, the single-well concept was tested. The steam was injected through an annulus to the heel of the well; the steam condensate and oil were produced through a nitrogen gas insulated FIGURE 1: The well profile of Imperial Oil's Horizontal Well Pilot 1 (HWP-1) (a vertical well for observation). (From Hawkins, 1979.) (Available in full paper) tubing inside the wellbore. Figure 1 shows the well profile. The vertical well shown in the figure was an observation well. During the 94-day test period over 3,500 m3 of cold water equivalent (CWE) dry steam was injected into the horizontal well, but only 9 M3 of bitumen was produced from a reservoir with high viscosity bitumen (200 Pa ·s).