Thermal Recovery Processes Research Articles

The Impact of Oil Viscosity Heterogeneity on the Production Characteristics of Tar Sand and Heavy Oil Reservoirs. Part II: Intelligent, Geotailored Recovery Processes in Compositionally Graded Reservoirs

Abstract Compositional and fluid property gradients are common and documented in conventional heavy oilfields and in super heavy oil occurrences such as oil sand reservoirs. In the severely biodegraded oils of both Athabasca and Peace River oil sand reservoirs, highly non-linear vertical and lateral chemical compositional and fluid viscosity gradients are common and have been shown to dramatically impact existing generation recovery processes such as SAGD and CSS. The fluid and geological heterogeneities at a variety of spatial scales in heavy oil and bitumen reservoirs, combined with the dynamic evolution of produced fluids during solvent or thermal recovery, should be integrated into recovery methods tailored to each reservoir which are operated using time-variant production strategies informed by produced fluid composition, flow rates and detailed history matching. We describe here, two new approaches of a new generation of transitional and initial thermal recovery processes that take advantage of mobility gradients: JAGD (J-well and Gravity Drainage) and gSAGD (mobility ratio optimized SAGD), which demonstrate significant improvements in recovery, economics and, thus, carbon dioxide emissions over existing thermal methods. Well configurations tailored to specific reservoir geometries and properties as well as fluid property distributions for primary thermal recovery increase initial production by 50 to 100%. Substantial cost savings are achieved in transitional cold primary to thermal secondary recovery methods (JAGD) by using a production J-well placed below what is initially a CHOPS production well, which is then later used to inject steam, as in SAGD. Three-dimensional reservoir simulations predict 25% more oil recovery with up to a 50% decrease in cumulative steam-oil ratio compared to standard SAGD in an identical reservoir. The JAGD process has many similarities to SAGD, such as steam trap control and potential for low pressure and solvent-assisted operation. Such geotailored processes (processes tailored, operated and optimized to reservoir fluid and geological heterogeneities) are expected to outperform conventional 'off the shelf' well placement designs and operating strategies. Introduction The bulk of the world's petroleum resources are stored in heavy oil and oil sand reservoirs. While some of this resource can be recovered by geotolerant (tolerant of unfavourable geology) recovery processes such as mining, these procedures are only suitable for shallow resources, are very costly and have high carbon dioxide emissions and other environmental penalties. Most of the world's heavy oil and bitumen resources are too deep to mine and so in situ recovery methods predominate. In situ recovery of viscous and poor quality oils currently relies on either high pressure primary production, as in cold heavy oil production, or thermal and/or solvent-based methods to mobilize the oil by reducing its viscosity. Average recoveries from heavy oil and oil sand reservoirs are typically low ranging from 5 to 15% for cold heavy oil production and from 30 to 85% for steam-based in situ processes. However, such processes are not very geotolerant. Also, profit margins are small because of high capital and operational costs.

Thermal and Hydraulic Matrix-Fracture Interaction in Dual-Permeability Simulation

Summary The shape factor concept, originally introduced by Barenblatt in 1960, provides an elegant and powerful upscaling method for fractured reservoir simulation. The shape factor determines the fluid and heat transfer between matrix and fractures when there is a difference in pressure or temperature between matrix blocks and the surrounding fractures. An appropriate specification of the shape factor is therefore critical for accurate modeling. Since its introduction, many different values for the shape factor have been proposed in the literature, among which the well-known Warren-Root and Kazemi shape factors. The aim of this paper is to show that the selection of the appropriate shape factor should not only depend on the “shape” and dimensions of matrix blocks, but should also take into consideration the character of the dominant underlying physical recovery mechanisms. We will show that by taking into account the dominant physical recovery mechanism, the apparent discrepancies in the shape factor values reported in the literature can be overcome. We derive a general expression for the shape factor that not only captures existing shape factor expressions, but also allows extensions to recovery mechanisms requiring a dual permeability approach. The paper is organized as follows. First, we briefly review the shape factors presented in the literature. We then derive the general expression for the (single-phase) matrix-fracture shape factor. Subsequently, we analytically derive a new shape factor that captures the transient in pressure/temperature diffusion processes. To compare and contrast the impact of the various shape factors, we consider three cases of increasing complexity. First, we consider pressure/temperature diffusion in a single 1D matrix block following a step change in the boundary conditions. Next, we consider isothermal gas/oil gravity drainage from a homogeneous stack. We compare fine-grid single-porosity simulations (in which the matrix is finely gridded and in which the fractures are explicitly represented) with coarse-grid dual-permeability simulations (in which the matrix-fracture interaction is modeled by shape factors). In the third step, we consider gas-oil gravity drainage of the same stack model, but now under steam injection. In this case, steam is injected at the top, and oil recovered from the base of the fracture system. Again, we compare fine-grid single-porosity simulations with coarse-grid dual-permeability simulations. We show that in this case, the constant (asymptotic) shape factor provides a good approximation to the heating of the stack. We will show, however, that with a constant (time-independent) shape factor, the initial fast heating of the matrix blocks cannot be captured. We show that the new transient shape factor, however, enables coarse-grid dual-permeability modeling of thermal recovery processes such that they reproduce fine-grid results.

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.

First Metal-PCP SAGD Field Test Shows Promise for Heavy-Oil Hot Production

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 110479," World's First Metal-PCP SAGD Field Test Shows Promising Artificial-Lift Technology for Heavy-Oil Hot Production: Joslyn Field Case" by Jean-Louis Beauquin, SPE, and Felix Ndinemenu, SPE, Total E&P; Gilles Chalier, Total E&P Canada; Lionel Lemay and Laurent Seince, PCM; and Alex Damnjanovic, KUDU Industries, originally prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November. The paper has not been peer reviewed. Finding a reliable artificial-lift (AL) pumping system for heavy-oil thermal recovery has been a challenge, mainly because of the high operating temperatures (greater than 150ºC). Available options such as rod pumps and electrical submersible pumps (ESPs), which are well proved in the industry, are not well suited for thermal production. While rod pumps offer high-temperature service, they are limited in the flow rate they can deliver. ESPs can handle high volumes of low-viscosity fluids but are still limited in terms of maximum operating temperature. Metal progressing-cavity-pump (PCP) technology has been developed to meet the high-temperature requirement of steam-assisted gravity drainage (SAGD) and other thermal-recovery processes. Introduction Recovery of the world's large reserves of extraheavy oil (found mainly in the oil sands of Canada and Venezuela) by thermal processes has been increasing because of the high price of oil. Key to this recovery process is AL, which is required because of the very high density and viscosity of the crude and the relatively low reservoir pressures. Although gas lift remains an AL option when high pressure gas is available, pumping techniques are more popular because of their relatively higher efficiency and ability to generate more pressure at the surface for delivery to the treating plant. However, the main challenge with hot pumping is the high temperatures often required [as much as 260°C for SAGD and 350°C for cyclic steam stimulation (CSS)]. The dominant pumping technologies available are beam/jack pumps, ESPs, and elastomer PCPs. All these pumps have their peculiar limitations for hot production. While beam pumps offer high-temperature service, they are limited in the flow rate they can deliver. ESPs can handle high volumes of low-viscosity fluids, but they are still limited in terms of maximum operating temperature. For PCPs, the limitation is operating temperature of the elastomer (maximum 150°C).

Electron irradiation damage and the recovery in a Zr-based bulk amorphous alloy Zr55Cu30Al10Ni5

Zr-based bulk amorphous alloys have been intensively studied because of their superiority in mechanical properties, corrosion resistance and micro-formability, and of great anticipation of their applications. The damage was introduced into a Zr-based bulk amorphous alloy Zr55Cu30Al10Ni5 by electron irradiation below 20K. The thermal recovery process from the irradiation damage was studied by using positron lifetime spectroscopy which sensitively detect open volume defects. The introduced damage was completely recovered at the temperature lower than the glass transition temperature by 200K. On the other hand, the X-ray diffraction pattern shows no crystalline peaks even after the recovery of the irradiation damage. This result is considerably different from the previous reports studied in conventional amorphous alloys.

Technology Focus: Heavy Oil (March 2008)

Technology Focus Recently, I served as cochairperson of the SPE Forum on "Enhanced Oil Recovery—What's Next?" The consensus of attendees was that while there is some promising technology, no game-changing enhanced-oil-recovery (EOR) technologies appeared to be on the immediate horizon. In the area of heavy hydrocarbons, on the other hand, it was expressed that in-situ upgrading of resources such as heavy oil, tar, and oil shale could be a game changer if more-vigorous work was conducted in the area of upgrading. The dawn for surface upgrading of bitumen appears to have occurred. Various possibilities for in-situ upgrading were discussed in some detail including electrical heating to create an upgrader and refinery-in-the-ground for oil shale; solvents tailored to precipitate the asphaltene fractions of crude oil; and in-situ combustion, in which the heaviest fractions of the crude are consumed selectively as fuel for combustion, thereby increasing the API gravity of the oil. A common theme is that in-situ upgrading is a complex process needing much more R&D. The conversion of trillions of barrels of oil equivalent to a lighter, sweeter synthetic crude oil is an exhilarating thought, especially given the possibility that such upgrading can be accomplished in a fashion that is close to being environmentally benign if it is carried out in situ with geological sequestration of any carbon dioxide created during upgrading. Considering the analogous time frame for implementation of the markedly simpler process of steamdrive for EOR, however, provides a sobering perspective. From the initial engineering report to commencement of a commercial project at Mt. Poso, a total of 20 years elapsed. Papers for this feature span many aspects related to heavy hydrocarbons including in-situ combustion, steam injection, optimization of thermal-recovery processes, chemical-based EOR for heavy oil, as well as artificial lift. Many questions linger for me regarding in-situ upgrading. Is an extended R&D time frame realistic today? If a significant portion of the technical workforce is poised to retire within a decade, where/when will the future workforce be trained for such an enormous challenge and who will be their mentors? Ultimately, could we extract the energy in the form of clean-burning hydrogen, or preferably methane, because of the significant natural-gas infrastructure already in place? Heavy Oil additional reading available at the SPE eLibrary: www.spe.org SPE 110479 • "World's First Metal PCP SAGD Field Test Shows Promising Artificial-Lift Technology for Heavy-Oil Hot Production: Joslyn Field Case" by Jean-Louis Beauquin, Total, et al. SPE 107949 • "Optimization of Cyclic Steam Stimulation Under Uncertainty" by K. Revana, Halliburton, et al. SPE 106908 • "Applicability of Water-Shutoff Treatment for Horizontal Wells in Heavy-Oil Reservoirs" by Francesco Verre, Imperial College, London, et al.

Surface Heave Induced by Steam Stimulation in Oil Sand Reservoirs

Abstract Steam stimulation is one of the viable methods to extract heavy oil from oil sand reservoirs in Alberta. In this thermal process, steam is injected into the oil sand reservoir. The oil sand formation expands due to an increase in pore pressure and thermal heating. This expansion results in an upward movement of the overburden, and thus, heaving of the free ground surface. This paper proposes an analytical method to estimate the surface heave induced by steam injection. The method was used to investigate the surface heave profiles under horizontal well injection. It was found that the surface heave profile is governed by the mass and heat transfer and distribution within the oil sand reservoir. The effect of the increase in pore pressure (or decrease in net overburden stress) on the surface heave is also compared to that due to the thermal expansion of the oil sand. The paper also discusses the limitations on the use of surface heave monuments and tiltmeters in monitoring the thermal recovery process. Introduction Thermal recovery processes such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD) involve large volume fluid and steam injection into oil sand reservoirs. Steam injection produces a dilatation of the oil sand reservoir due to an increase in pore pressure and temperature of the reservoir. The overburden containing the reservoir responds to the steam injection by upward heaving of the free ground surface. Surface heave of up to 20 cm has been recorded(1). The profile of the surface heave reflects the distribution of the injected steam within the oil sand formation. Monitoring the surface heave evolution during the steaming operation may be used as an inverse method of monitoring the steam injection operation. This paper presents an analytical method to determine the surface heave profile induced by steam stimulation for a horizontal well. Parametric studies were conducted to investigate the important factors contributing to the surface heave profile. Problem Statement This study considers a steam stimulation operation using a horizontal well. Steam is injected into a horizontal well installed within an oil sand formation of finite thickness (Figure 1). Since the overburden serves as a competent hydraulic barrier to the fluid upward migration, it is assumed that the injected steam is contained within the oil sand reservoir, which results in an expansion of the reservoir. Thus, steam injection using a horizontal well can be treated as a two-dimensional plane strain problem. Figure 1 illustrates the problem statement. The objective of the exercise is to determine the surface heave profile as a function of the amount of steam injected into the horizontal well. Methodology Steam stimulation is a complex thermal hydraulic mechanical multiphase flow process. Determination of injected fluid distribution within the reservoir is not trivial. Since the shale overburden serves as a competent hydraulic barrier to the fluid upward migration, the geomechanical responses in the overburden are governed by the expansion pattern of the oil sand reservoir due to steam stimulation.

Application of Strain-Induced Permeability Model in a Coupled Geomechanics-Reservoir Simulator

Abstract A fully coupled geomechanics-reservoir model is developed to simulate the directional changes in permeability due to fluid injection and production in a reservoir. The model is implemented numerically by fully coupling a geomechanics model with a single-phase reservoir flow model using the finite element method. A strain-induced permeability model is developed based on the analysis of the grain fabric of intact and sheared oil sand specimens using a thin section imaging method. It can quantify the changes in permeability when material experiences shear deformation. In addition, the directions of the principal values of permeability are not restricted to some arbitrary axes, but governed by the induced strains. Thus, the effects of stress path and stress level are implicitly considered through effective stress-strain constitutive laws. The transient pressure response of a water injection test in a horizontal well is analyzed. Parametric studies are also conducted to investigate the effects of permeability, deformability and initial stress conditions on the injection pressure. It is found that the changes in permeability resulting from dilations of the oil sands cannot be captured using the conventional permeability model as a function of volumetric strain because the volumetric strain is small. However, the strain-induced permeability model can accurately reflect the directional increase in permeability during water injection. It is shown that the induced pore pressure is relatively insensitive to the deformation modulus of the reservoir, as compared to the permeability. The initial stress condition dominates the propensity of hydraulic fracturing. Introduction Geomechanics plays a key role in accounting for rock deformations due to pore pressure and temperature changes resulting from fluid injection and production in a thermal reservoir. During fluid injection and production, absolute permeability at any given location may change in response to localized changes in stress within the rock pore system owing to changes in reservoir pressure. Pore pressure changes can, in turn, influence the effective reservoir stress (overburden pressure minus pore pressure) which can alter the pore geometry of the reservoir rock; especially the shape and dimension of the pore and the pore throats(1–7). The geomechanical behaviour of porous media has become increasingly important in deformable and fractured reservoirs. In current geomechanics-reservoir coupled simulators, the permeability of the rock is assumed to be transversely or orthogonally isotropic(8,9). In other words, the direction of flow is aligned with the pressure gradient. This simplifying assumption is not valid in many cases. For example, the permeability of fractured rock is substantially dependent on microfractures. Therefore, the dominating orientation of the fractures can make the direction of flow different from that of the pressure gradient(10). Another example of permeability anisotropy is demonstrated in thermal recovery processes, such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD). In these thermal recovery processes, shear dilation deformation takes place in local areas due to the increase of pore pressure, thereby enhancing permeability in these areas(11,12). Clearly, an understanding of permeability anisotropy is important. However, in the petroleum literature, the permeability change of a reservoir formation subjected to deformation changes is usually determined as a function of volumetric strain or porosity, which relates to the mean or minimum effective stress.

Plastic bending and shape-memory effect of double-wall carbon nanotubes

Plastic bending of (5,5)@(10,10) double-wall carbon nanotube is analyzed using nudged elastic band minimum energy path calculations. At lower applied bending curvature, only the outer tube deforms plastically. However, at higher bending curvature, both the inner and outer tubes deform plastically. We find that the plastic deformation of the outer tube is more difficult than that of isolated single-wall carbon nanotube of the same diameter due to tube-tube interactions. In contrast, the plastic deformation of the inner tube is not strongly affected by the presence of the outer tube. We also analyze the shape-memory effect (SME) discovered experimentally, which is a thermal recovery process from the plastically bent state to the straight defect-free state, which can be repeated multiple times. We analyze the physics behind SME of carbon nanotubes, which is quite different from that of traditional shape-memory alloys.

Heavy oils: Their shear story

Heavy oils are important unconventional hydrocarbon resources with huge reserves and are usually exploited through thermal recovery processes. These thermal recovery processes can be monitored using seismic techniques. Shear-wave properties, in particular, are expected to be most sensitive to the changes in the heavy-oil reservoir because heavy oils change from being solid-like at low temperatures to fluid-like at higher temperatures. To understand their behavior, we measure the complex shear modulus (and thus also the attenuation) of a heavy-oil-saturated rock and the oil extracted from it within the seismic frequency band in the laboratory. The modulus and quality factor [Formula: see text] of the heavy-oil-saturated rock show a moderate dependence on frequency, but are strongly influenced by temperature. The shear-wave velocity dispersion in these rocks is significant at steam-flooding temperatures as the oil inside the reservoir losesviscosity. At room temperatures, the extracted heavy oil supports a shear wave, but with increasing temperature, its shear modulus decreases rapidly, which translates to a rapid drop in the shear modulus of the heavy-oil-saturated rock as well. At these low to intermediate temperatures [Formula: see text], an attenuation peak corresponding to the viscous relaxation of the heavy oil is encountered (also resulting in significant shear-wave velocity dispersion, well described by the Cole-Cole model). Thus, shear-wave attenuation in heavy-oil rocks can be significantly large and is caused by both the melting and viscous relaxation of the heavy oil. At yet higher temperatures, the lighter components of the heavy oil are lost, making the oil stiffer and less attenuative. The dramatic changes in shear velocities and attenuation in heavy oils should be clearly visible in multicomponent seismic data, and suggest that these measurements can be qualitatively and quantitatively used in seismic monitoring of thermal recovery processes.

Incorporation of Strain-Induced Permeability Model in a Deformation-Flow-Heat Transfer Simulator

Abstract This paper extends the fully coupled geomechanics and reservoir simulator previously developed by the authors to include temperature effects using finite element methods (FEM). The strain-induced permeability model and the full permeability tensor are incorporated into the developed deformation-flow-heat transfer simulator. Numerical examples are given to evaluate the validity of the FEM model. The simulation results demonstrate that the strain-induced permeability model has significant effects on wellbore pressure response and geomechanical behaviour of the reservoir. Introduction The simulation of fluid flow and heat transfer through porous media has been a branch of research undergoing rapid growth in the chemical and petroleum field. Conventional reservoir simulators usually calculate the effects of deformation on pore volume change through the concept of reservoir compressibility and mainly focus on homogeneously or transversely isotropic porous structures, although in most practical problems the porous medium is anisotropic either due to geological processes or due to human beings' industrial activities. Recently, much attention has been paid to the importance of geomechanics in reservoir simulation, particularly in the thermal recovery of oil from oil sands reservoirs. Deformations in an oil sands reservoir are induced by the changes of pore pressure and temperature due to fluid injection and production in thermal recovery processes. In turn, the changes in deformation affect permeability. The permeability change of a reservoir formation subjected to deformation changes is usually assumed as a function of porosity or volumetric strain, which is a scalar variable. Thus, the changes in permeability are equal in all directions even though the changes in strains are different in each direction. Wong(1) analyzed the grain fabric of intact and sheared oil sand specimens using the thin section imaging method. He observed that even in intact natural oil sands specimens, the hydraulic radius and tortuosity factors vary in vertical and horizontal directions resulting in an intrinsic anisotropy in permeability. Based on theoretical and laboratory works, he developed a new permeability model for deformable porous media(2). This model assumes the permeability tensor is governed by induced principal strains. It can quantify the changes in permeability when the material experiences shear deformation and the changes in permeability can be anisotropic. In order to account for reservoir deformations due to pore pressure and temperature changes resulting from production and fluid injection, coupled geomechanics reservoir heat transfer simulation is necessary(3). Conventional reservoir simulators usually use the finite difference method (FDM) and assume permeability is either an isotropic or diagonal tensor. It is impractical to develop coupled geomechanics reservoir simulators based on FDM numerical schemes due to the complexity. A coupled deformation-flow-heat transfer simulator using finite element methods (FEM) was developed by implementing temperature in an earlier developed geomechanics reservoir simulator(4). The full permeability tensor and the strain-induced permeability model were incorporated into the simulator. It was then used to conduct a coupling analysis of two-dimensional non-isothermal single-phase fluid flow in elastic porous media. Coupled FEM Model Formulation Prior to the formulation of the governing equations, we need to make a few assumptions with respect to the FEM model(5, 6):

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.

814 二層カーボンナノチューブの塑性曲げ変形及びその回復過程(OS08.電子・原子・マルチシミュレーションに基づく材料特性評価(4))

Plastic bending of (5,5)@(10,10) double-wall carbon nanotube (DWNT) is analyzed using nudged elastic band minimum energy path calculations. At lower applied bending curvature, only the outer tube deforms plastically. But at higher bending curvature, both the inner and outer tubes deform plastically. We find the plastic deformation of the outer tube is more difficult than that of isolated single-wall carbon nanotube (SWNT) of the same diameter, due to tube-tube interactions. In contrast, the plastic deformation of the inner tube is not strongly affected by the presence of the outer tube. We also analyze the shape memory effect (SME) discovered experimentally, which is a thermal recovery process from the plastically bent state to the straight defect-free state, that can be repeated multiple times. We analyze the physics behind SME of carbon nanotubes, which is quite different from that of traditional shape memory alloys.

Structural Integrity of Casing and Cement Annulus in a Thermal Well Under Steam Stimulation

Abstract Steam stimulation is one of the viable methods to extract heavy oil from oil sand reservoirs. In this thermal process, the injection well is subjected to high temperatures. Numerical simulations were used to investigate the structural integrity of the well in such a high temperature environment. In this study, stresses in the metal casing, cement annulus and surrounding shale formation were examined in detail to evaluate if the induced stresses exceed the material strengths under varying boundary conditions. These include the effect of heating rate, poor cement and shale formation properties. Introduction In Alberta, thousands of deviated wells are drilled through shale formation to extract heavy oil from underneath oil sand formation using thermal recovery processes. Thermal deviated wells in shale impose more technical challenges than conventional wells in consolidated rock because of their unique features. Thermal recovery processes, such as steam assisted gravity drainage and cyclic steam stimulation, involve high temperature operations up to 300 °C. Shales found in Alberta are compaction type without strong cementation, and have been known to swell and lose structural integrity upon exposure to water-based fluids. The occurrence of casing equipment impairment and failure after years of service in a shale formation are frequent. A completed deviated well is made up of a series of annular rings of steel casing, oil well cement and shale of varying thicknesses. There are differences in mechanical, hydraulic and thermal properties among these materials. The overall response of a thermal well subject to heating is governed by not only each material, but also the properties of interfacial steel-cement and cement-shale interaction. Material properties of steel, oil well cement and shale have been well studied separately. However, the behaviour of steel-cement and cement-shale interfaces have not received much attention because the interaction behaviour is very complex, dependent on the imposed boundary conditions. In a well completion, a borehole is drilled and advanced with drilling mud. Then, steel casings are inserted into the drilled hole filled with mud. The mud in the annular space between the steel casing and the drilled hole wall is removed by a clear wash or spacer fluid, followed by the cement slurry. In an idealized situation, all drilling mud should be removed and the annular space should be filled with cement slurry. However, the complete displacement of drilling mud by the spacer fluid and cement slurry may not be achieved. Often a residual mud layer adheres to the inside and outside surfaces of the borehole and casing, respectively. The thickness of this layer depends on the displacement processes (fluid velocity and annular space) and fluid rheology and density. Undesired mixing can be induced because there are differences in fluid rheology and density of drilling mud, washer fluid and cement slurry (non-Newtonian fluids). Local channel or fingering could occur in narrow spaces since the fluid displacement takes place in a narrow eccentric annular configuration bounded by the ircumferential surfaces of the drilled well and the steel casing(1).

Overview: Reservoir Performance and Monitoring (September 2006)

Advances in technology enable improved reservoir characterization as well as improved measurement and allocation of relevant production and other data. The continuous advance in reservoir monitoring improves efforts in finding unrecovered hydrocarbons in fields with long production histories. However, as one of the featured papers shows, even in such fields, considerable production-forecasting uncertainties exist. Thanks to ever-increasing computing power, the uncertainties in production forecasting in these cases can be quantified and, thereby, managed. Various methods for assisted history matching have been used successfully to perform this task. Time-lapse (4D) seismic has proved very successful in reducing uncertainties and finding remaining hydrocarbons. The technology is still developing at a fast pace. The application of 4D seismic has expanded from offshore to onshore heavy-oil developments. Because this technology is one of the few sources of surveillance information away from the well, new ideas are evolving of how to advance the methodology further. Another featured paper shows how geomechanical data were incorporated with the 4D seismic analysis, which might open another field for application of this method. Geomechanical effects are important in various aspects of hydrocarbon recovery. They can be used in combination with 4D seismic, as mentioned above, and they are very important in water-injection and thermal-recovery processes. The third featured paper provides insight into coupling geomechanical effects and fluid flow. Reservoir Performance and Monitoring additional reading available at the SPE eLibrary: www.spe.org SPE 95419 "Production Monitoring Through Openhole Gravel-Pack Completions Using Permanently Installed Fiber-Optic Distributed-Temperature Systems in the BP-Operated Azeri Field in Azerbaijan" by G. Brown, SPE, Schlumberger, et al. SPE 96897 "Mapping Fluid Flow in a Reservoir Using Tiltmeter-Based Surface-Deformation Measurements" by J. Du, SPE, Pinnacle Technologies Inc., et al. Available at the OTC Library: www.otcnet.org OTC 18222 "Constraining Reservoir Uncertainty With Frequent 4D-Seismic Data at Valhall Field" by H.S. Lane, SPE, BP plc, et al.

Interrelationship of Temperature and Wettability on the Relative Permeability of Heavy Oil in Diatomaceous Rocks

Summary The evaluation of thermal-recovery processes requires relative permeability functions, as well as information about the effects of temperature on these functions. There are significant challenges encountered when estimating relative permeability from laboratory data, such as the accuracy of measurements and generalized assumptions in the interpretation techniques. A novel method is used here to estimate relative permeability and capillary pressure from in-situ aqueous-phase saturation profiles obtained from X-ray computerized tomography (CT) scanning during high-temperature imbibition experiments. Relative permeability and capillary pressure functions are interpreted simultaneously, including possible nonequilibrium effects. Results obtained show a systematic shift toward increased water-wettability with increasing temperature for diatomite reservoir core. The measured changes in relative permeability are linked to the effect of temperature on the adhesion of oil-coated fines to rock surfaces and, ultimately, to rock/fluid interactions.

Quench and thermal recovery in a superconducting fault current limiter with artificial weak zones

We report results on the behaviour of an inductive fault current limiter prototype with weak zones artificially created. The superconducting elements are Bi-2223 rings and the tests have been realized with the device on a Helium gas environment at 77.3 K. We found that the artificial weak zones can play the main role during the limitation under a current fault and on the thermal recovery process after the fault, which could be used to improve the performance of these devices. Our results show also that the artificial weak zones could balance, in addition, the influence of other natural defects which could lead to non-uniform normal-superconducting transitions, the formation of hot spots, etc.

Low temperature [formula omitted] recovery started by [formula omitted] nanosecond pulses: An autocatalytic process?

The kinetics of the low temperature recovery from metastable EL 2 centers in GaAs, induced by strong 1.06 μ m laser pulses, have been observed by measuring the time dependent transmittance of a very weak CW 1.05 μ m laser beam. Besides an initial fast recovery caused by the laser pulse, the action of the laser also triggers a much slower recovery, whose behavior resembles that of the autocatalytic thermal recovery process described by Fukuyama et al. [Phys. Rev. B 67 (2003) 113202]. As in the autocatalytic process, we observe a time-lag between the pulse and the beginning of the recovery, known as incubation time, which is reduced as the pulsed laser intensity increases. On the other hand, differently from the thermal recovery, the recovery induced by the pulsed laser is incomplete, and its rate increases with the intensity of pulsed laser and the probe laser as well. The results suggest that the pulsed laser “activates” a certain number of centers which can then undergo a low temperature recovery.

Ion-induced damage accumulation and electron-beam-enhanced recrystallization inSrTiO3

Damage accumulation in strontium titanate $(\mathrm{Sr}\mathrm{Ti}{\mathrm{O}}_{3})$ from $1.0\phantom{\rule{0.3em}{0ex}}\mathrm{MeV}$ Au irradiation has been investigated at temperatures from $150\phantom{\rule{0.3em}{0ex}}\text{to}\phantom{\rule{0.3em}{0ex}}400\phantom{\rule{0.3em}{0ex}}\mathrm{K}$. The relative disorder on the Sr and Ti sublattices at the damage peak has been determined as a function of local dose and temperature. A disorder accumulation model has been fit to data from this study and from the literature, indicating that defect-stimulated amorphization is the primary amorphization mechanism up to $\ensuremath{\sim}360\phantom{\rule{0.3em}{0ex}}\mathrm{K}$. High-dose irradiation at $400\phantom{\rule{0.3em}{0ex}}\mathrm{K}$ leads to formation of an amorphous surface layer. Analyses of the temperature dependence for amorphization indicate that the amorphization kinetics are consistent with irradiation-enhanced and thermal recovery processes with activation energies of $0.1\ifmmode\pm\else\textpm\fi{}0.05\phantom{\rule{0.3em}{0ex}}\mathrm{eV}$ and $0.7\ifmmode\pm\else\textpm\fi{}0.1\phantom{\rule{0.3em}{0ex}}\mathrm{eV}$, respectively. Under $200\phantom{\rule{0.3em}{0ex}}\mathrm{keV}$ electron-beam irradiation, the epitaxial recrystallization rates are orders of magnitude higher than thermal rates, and an activation energy of $0.1\ifmmode\pm\else\textpm\fi{}0.05\phantom{\rule{0.3em}{0ex}}\mathrm{eV}$ is determined for the e-beam enhanced recrystallization processes.

High optical power dependence of the EL2 recovery in GaAs

In this work, a new way of achieving the recovery from the EL2 metastable state is reported and analyzed theoretically. Despite being an old problem, no definitive picture of the EL2 center has been established to date. For this reason, long past the days of effervescent research on the EL2, new models and investigations keep appearing in the literature as, for example, the recently proposed autocatalytic model to describe the inter-defect correlation during the thermal recovery process [A. Fukuyama, T. Ikari, Y. Akashi, M. Suemitsu, Phys. Rev. B 67 (2003) 113202]. In the course of a re-evaluation of the EL2 for nanosecond volume holographic storage, we found that a strong laser pulse is capable of destroying the metastable state and decided to investigate further this effect. The experiment reported here consists of monitoring the transmission of a λ=1.05μm continuous-wave (CW) laser, used to populate the metastable state, while subjecting the sample to the incidence of a strong λ=1.06μm laser pulse. A full simulation of the problem has been carried out and the results could be fit very well by assuming a recovery induced by electron–hole recombination and a nonlinear free-carrier production mechanism. It is perhaps worth noting that such a fast recovery induced by the nanosecond laser may prove to be an interesting tool to initiate a recovery process (even at low temperature) in a controlled way to check the predictions of the recently proposed autocatalytic recovery process.