Thermal Recovery Processes Research Articles

Solvent-Chamber Development in 3D-Physical-Model Experiments of Solvent-Vapour Extraction (SVX) Processes With Various Permeabilities and Solvent-Vapour Qualities

Summary Solvent-vapour extraction (SVX) processes offer an attractive alternative to thermal recovery processes by being less energy intensive and are more suitable for thinner, partially depleted reservoirs. A typical SVX process uses solvent injection to dilute the heavy oil by reducing its viscosity, allowing it to be mobilized for production. During this process, the injection of hydrocarbon solvents results in partial deasphalting of the heavy oil, thus reducing its viscosity and enhancing the process performance further. This work examined the formation and growth of solvent chambers in laterally and vertically spaced horizontal injector/producer well pairs in porous media with five different permeabilities and three different solvent-vapour qualities. Consolidation of the porous media caused by asphaltene precipitation was also analyzed. Thermal-imaging and model excavation studies were performed to investigate the formation and growth of solvent chambers for seven different experiments conducted on a large 3D-physical-model apparatus. The important findings from this study are as follows: During solvent injection, one or more solvent fingers develop between the injector and producer. The dominant solvent finger becomes a conduit that grows into a solvent chamber connected to the injection well in the upper portion of the reservoir, and develops into an oil-drainage conduit connected to the production well in the lower portion of the reservoir. Solvent dispersion layers are located on the margins of both the solvent chambers and the oil-drainage conduits. The location and development of these nonuniform solvent chambers and oil-drainage conduits are unpredictable, and the oil-drainage conduits do not grow significantly in diameter once connected to the production wellbore, limiting the wellbore inflow efficiency and conformity. Asphaltene precipitation and migration can aggravate this inflow problem, reducing the SVX process performance further. SVX performance can be improved by increasing the number and diameter of oil-drainage connections between the solvent chamber and the production well, and by controlling the oil deasphalting process. This can be performed by optimizing injection- and production-wellbore geometries, and by optimizing solvent-injection rates and vapour quality.

Influence of temperature on seismic velocities and complex conductivity of heavy oil-bearing sands

The joint inversion of seismic and electromagnetic data can be of great use to monitor the steam-assisted production of heavy oils in field conditions. Seismic velocity and complex conductivity laboratory measurements were performed on three heavy oil-bearing sands at confining and pore pressures similar to field conditions. One of the samples (8H) was initially oil-wet and the two other samples (5P-3A and P-1A) were initially water-wet. Low-frequency stress-strain measurements and complex conductivity measurements were performed during two heating cycles (at constant temperature, 10°C steps in the range 20°C–70°C). The temperature was first increased from 20°C–70°C simulating initial stage in a thermal recovery process. During this temperature increase, sample 8H changed to water-wet with a clear irreversible signature on the seismic and electrical data. Then the temperature was decreased and cycled a second time in the temperature range 20°C–70°C. The seismic and complex conductivity responses were found to be identical at each temperature for the temperature decrease of the first heating cycle and the second cycle. For the water-wet samples (5P-3A and P-1A), the compressional and shear velocities decreased with the increase of temperature and the in-phase and quadrature conductivities increased with the temperature with the same temperature sensitivity coefficient ([Formula: see text]). After these two heating cycles, we extracted the heavy oil from sample 8H and additional complex conductivity measurements were performed at different salinities to determine the two Archie’s exponents [Formula: see text] and [Formula: see text]. We found [Formula: see text] for the cementation exponent while the saturation exponent is given by [Formula: see text] when the sand is oil-wet and [Formula: see text] when the rock is water-wet. The power-law exponent for the quadrature conductivity of the water-wet samples is [Formula: see text].

Technology Development for Solvent-Based Recovery of Heavy Oil

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150706, ’An Integrated Technology-Development Plan for Solvent- Based Recovery of Heavy Oil,’ by Thomas J. Boone, SPE, Imperial Oil Resources, and Chick Wattenbarger, SPE, Scott Clingman, SPE, and Jasper Dickson, SPE, ExxonMobil Upstream Research Company, prepared for the 2011 SPE Heavy Oil Conference and Exhibition, Kuwait City, Kuwait, 12-14 December. The paper has not been peer reviewed. ExxonMobil and its Canadian affiliate Imperial Oil Resources are pursuing an integrated research program to develop the next-generation heavy-oil-recovery processes that use hydrocarbon solvents as a mobilizing agent. Key benefits of solvent-based processes are improved environmental performance, improved economics, and recovery of a resource that is not achievable with thermal processes. Introduction As used herein, a solvent-assisted process is one in which solvent is added to steam whereas a solvent-based process is one in which solvent is substituted for steam. The term solvent process is used to refer to both solvent-assisted and solvent-based recovery processes. These processes use solvents—typically, light hydrocarbons (e.g., propane or butane) or mixtures of light hydrocarbons (e.g., gas condensates or diluents)—to mobilize the heavy oil in the reservoir. Thermal processes including steam-flooding, cyclic steam stimulation (CSS), and steam-assisted gravity drainage (SAGD) are highly effective recovery processes that enable economical recovery levels that equal or exceed recoveries achieved in most conventional oil fields. Thermal processes are very effective at recovering heavy oil from the best-quality resource: thick, clean sands with high bitumen saturation and high porosity and permeability. However, the efficiency of thermal processes degrades significantly and these processes become less economically attractive in lower-quality resources. Solvent processes have the potential to enable economical recovery of additional resource that cannot be recovered economically with thermal processes. Solvent-Recovery-Process Classification The technical success of thermal-recovery processes lies fundamentally in the three to five order-of-magnitude viscosity reductions that can be achieved when heavy oil is heated to temperatures that can be achieved practically with steam. Solvent/heavy-oil mixtures can achieve similar viscosity reductions in combination with heat or with only the addition of solvent. Fig. 1 shows the effect of temperature and solvent concentration on the resulting mixture viscosity. Typically, heavy-oil-recovery processes endeavor to reduce the flowing-mixture viscosity to 10 cp or lower. While there is a wide variety of solvents that can bring about similar viscosity reductions, the need for relatively low-cost, commercially available, large volumes with acceptable health and environmental characteristics tends to favor the use of relatively pure or mixed light alkanes, such as propane, butane, pentane, gas condensates, or pipeline-quality diluents.

Impact of Different SAGD Well Configurations (Dover SAGD Phase B Case Study)

Summary The volume of heavy oil and bitumen in the oil-sands deposits in western Canada is similar to that of conventional crude oil in the Middle East. This resource is immense but is difficult and energy intensive to extract because the viscosity of the oil is high, typically greater than 100,000 to 1,000,000+ cp at original reservoir conditions. Current commercial thermal-recovery processes used include steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS). These methods are energy intensive, emit significant amounts of CO2 into the atmosphere, and use large volumes of water to recover the oil. In this work, the focus is on SAGD processes. It has been demonstrated that operating strategy can be altered to improve SAGD performance, but it is not clear how well configuration can be changed to improve recovery, energy intensity, thermal efficiency, water use, and flue-gas emissions. This paper examines the impact of position and geometry of steam injectors on the performance of steam-based gravity-drainage processes in a heterogeneous reservoir. Different injection-well configurations including single horizontal (typical SAGD), offset SAGD, and vertical/horizontal well combinations have been evaluated by using a detailed, 3D, geostatistically populated, large-scale thermal reservoir-simulation model derived from core-data examinations of the Dover pilot site. The research reveals how injection-well configuration impacts energy delivery to the reservoir, how it affects thermal efficiency, and how it changes the evolution of the steam-conformance zone and oil-flow dynamics in the reservoir. The results suggest that several vertical injectors have the potential to deliver steam more efficiently than a single horizontal injector.

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

Pressure and pressure derivative analysis without type-curve matching for thermal recovery processes

In recent years, a constant increase of oil prices and declining reserves of coventional crude oils have produced those deposits of lights to be considered economically unattractive to be produced as an alternative way to keep the world´s oil supply volume.
 Heavy oil deposits are mainly characterized by having high resistance to flow (high viscosity), which makes them diffi-cult to produce. Since oil viscosity is a property that is reduced by increasing the temperature, thermal recovery techniques -such as steam injection or in-situ combustion- have become over the years the main tool for tertiary recovery of these oils.
 Composite reservoirs can occur naturally or may be artificially created. Changes in reservoir width, facies or type of fluid (hydraulic contact) forming two different regions are examples of two-zone composite reservoirs occurring naturally. On the other hand, such enhanced oil recovery projects as waterflooding, polymer floods, gas injection, in-situ combustion, steam drive, and CO2 miscible artificially create conditions where the reservoir can be considered as a composite system. A reservoir undergoing a thermal recovery process is typically idealized as a two-zone composite reservoir, in which, the inner region represents the swept region surrounding the injection well and the outer region represents the larger portion of the reservoir. Additionally, there is a great contrast between the mobilities of the two zones and the storativity ratio being different to one.
 In this work, the models and techniques developed and implemented by other authors have been enhanced. Therefore, the interpretations of the well tests can be done in an easier way, without using type-curve matching. A methodology which utilizes a pressure and pressure derivative plot is developed for reservoirs subjected to thermal recovery so that mobilities, storativity ratio, distance to the radial discontinuity or thermal front and the drainage area can be estimated. The precedence of the heat source (in-situ combustion or hot injected fluids) does not really matter for the application of this methodology; however, this was successfully verified by its application to synthetic and field examples of in-situ combustion. The point of comparison was the input data used for simulation for the synthetic case and the results from simulation matching and from previous studies for the field cases.

Negative Saturation Approach for Non-Isothermal Compositional Two-Phase Flow Simulations

This article deals with developing a solution approach, called the non-isothermal negative saturation (NegSat) solution approach. The NegSat solution approach solves efficiently any non-isothermal compositional flow problem that involves phase disappearance, phase appearance, and phase transition. The advantage of the solution approach is that it circumvents using different equations for single-phase and two-phase regions and the ensuing unstable procedure. This paper shows that the NegSat solution approach can also be used for non-isothermal systems. The NegSat solution approach can be implemented efficiently in numerical simulators to tackle modeling issues for mixed CO2–water injection in geothermal reservoirs, thermal recovery processes, and for multicontact miscible and immiscible gas injection in oil reservoirs. We illustrate the approach by way of example to cold mixed CO2–water injection in a 1D geothermal reservoir. The solution is compared with an analytical solution obtained with the wave-curve method (method of characteristics) and shows excellent agreement. A complete set of simulations is carried out, which identifies six bifurcations. The two main bifurcations are (1) when the most downstream compositional wave is replaced by a compositional shock and (2) when an extra Buckley–Leverett rarefaction appears. The plot of the useful energy (exergy) versus the CO2 storage capacity shows a Z-shape. The top horizontal part represents a branch of high exergy recovery/relatively lower storage capacity, whereas the bottom part represents a branch of lower exergy recovery/higher storage capacity.

The Assessment of Melanoma Risk Using the Dynamic Infrared Imaging Technique

Melanoma is the deadliest form of skin cancer. Each year more than 53,600 people learn that they have melanoma, and around 8700 people die from melanoma in the United States. Early detection is the key to improving survival in patients with malignant melanoma. We developed a thermal (infrared) imaging system that allows accurate measurements of small temperature differences on the skin surface with the aim to diagnose malignant pigmented skin lesions at an early stage of the disease. The imaging method we developed relies on active infrared imaging and a multimodal image analysis strategy, including involuntary body/limb motion correction and interactive lesion segmentation for detecting malignant lesions. The imaging system described in the paper was tested in a pilot patient study in which patients who possess a pigmented lesion with a clinical indication for biopsy were selected to participate. The lesion and the surrounding healthy skin were cooled by air at 15 °C for 30–60 s, and the thermal recovery was imaged with the infrared camera after the removal of this cooling stress. We found that the benign lesions have a thermal recovery similar to normal skin, whereas the thermal recovery of the melanoma lesion is different. It was observed that a malignant skin lesion has a higher temperature than healthy skin during the thermal recovery process (up to 2.2 °C higher for a Clark’s level II melanoma). The present study shows the feasibility of dynamic thermal imaging in distinguishing malignant pigmented lesions from benign, look-alike pigmented lesions.

Design and Practice of Steam Flooding on Anisotropic Heavy-Oil Reservoir with Edge-Bottom Water

Liaohe block J is a super heavy oil reservoir with relatively strong anisotropy and active edge-bottom water condition. After more than two decades of huff and puff production, the block now reaches a low production rate period, and the local part of the block also encounters serious edge-bottom water invasion. Now steam flooding is used as a switching method to invert the production decline tendency. Applied with thermal recovery process and numerical simulation method, reservoir pressure at flooding conversion, pressure control in steam flooding, injection-production parameters and well pattern are used to optimize the key techniques of steam flooding design. The design results are as follows: the reservoir pressure at flooding conversion as well as during steam flooding process should be controlled below 5 Mpa; the unit volume steam injection rate is 1.65t/d.hm2.m and the bottom-hole steam quality of injecter is no less than 53%; the injection-production ratio is 1.1:1 and inversed 9 point pattern with a 83m well space is used. The steam flooding pilot has been carried out for more than 2 years and obtains favorable benefits.

Determination of the formation temperature from shut-in logs: Estimation of the radius of thermal influence

As a consequence of drilling and completion operations most wells have reduced permeability near the borehole (skin zone). This may result in a corresponding change of thermal conductivity of formations near the borehole. At the same time the mathematical models, which describe the process of thermal recovery of formations are based on the assumption that the thickness of the radius of heated zone (during circulation of the drilling mud) is significantly larger than the well radius (or skin zone). It is shown below that the radius of the heated zone (radius of investigation or radius of thermal influence) can be approximated by simple formulas. It is shown that for six field bottom-hole temperature surveys the radius of thermal influence (RTI) is too small, and for this reason, the duration of the drilling mud circulation period should increased.

Constitutive modeling of the creep behavior of single crystal superalloys under non-isothermal conditions inducing phase transformations

The prediction of the viscoplastic behavior of Ni-based single crystal superalloy is still a challenging issue due to the non-isothermal loadings which can be encountered by aeronautical engines components such as high pressure turbine blades. Under particular in-service conditions, these materials may experience temperature cycles which promote the dissolution of the strengthening γ′ phase of the material on (over)heating, and subsequent precipitation on cooling, leading to a transient viscoplastic behavior. New internal variables representing the microstructural changes under those specific thermal loadings have been introduced in the framework of crystal plasticity using a macroscopic approach (no representation of the γ/γ′ microstructure of the alloy) to account for the transient creep behavior induced by microstructure changes. This modeling approach captures first order effects on the creep behavior due to (a) γ′ precipitates volume fraction evolution of each kind of particles of a bimodal distribution of precipitates (which evolves according to thermal history), (b) recovery of the dislocation density and, (c) material orientation. In addition, a damage law keeping in memory all the thermal history and recovery processes has been introduced to account for the unconventional post-overheating creep life. This model is calibrated on non-isothermal creep experiments on [0 0 1] oriented single crystals made of MC2 alloy. It is able to predict creep strain (primary, secondary, tertiary), whatever the temperature history of the material. In addition, it can be used to quantify the effect of slight variation of the as-received γ′ volume fraction on the creep behavior.

Thermal Streamline Simulation for Hot Waterflooding

Summary We explore the extension of streamline simulation to thermal-recovery processes. For each global timestep, we first compute the pressure field on an Eulerian grid. We then solve for the advective parts of the mass balance and energy equations along the individual streamlines. At the end of each global timestep, we account for the nonadvective terms of the transport equations on the Eulerian grid along with gravity, using the operator splitting method. We included temperature-dependent viscosity and account for thermal expansion of the fluids. We tested our streamline simulator on 2D heterogeneous quarter five-spot problems and compared the results with those computed by a commercial thermal simulator both for accuracy and computational efficiency. We present sensitivity studies for effects of fluid compressibility, gravity, and thermal-conductivity. For the cases investigated, our thermal streamline simulator is capable of producing accurate results at a computational cost that is significantly lower than that of existing Eulerian simulators.

Induced H2S formation during steam injection recovery process of heavy oil from the Liaohe Basin, NE China

H2S is generally very low in fresh water lacustrine origin oil and gas deposits, while unusual high amounts of H2S in thermal recovery pilot areas may be formed in situ during steam injection process. Present paper shows such kind of case study from the Liaohe Basin, NE China, where abundant heavy oil accumulated in the Eogene sandstone reservoirs with burial depth shallower than 1000 m. Qi 40 Block is one of pilot areas where steam injection was applied for heavy oil recovery. Almost no H2S can be detected in initial gas production, while up to 3% of H2S occurs in associated gas after thermal recovery. We proposed that most of H2S were derived from the TSR (thermochemical sulfate reduction) during thermal recovery, even though minor amount of H2S from thermal decomposition of organosulfur compound (TDS) within oil cannot be ruled out. Heavy oils in the Liaohe Basin contain very low amount of sulfur (generally < 0.3%), which cannot generate decent amount of H2S during thermal decomposition of heavy oil. However, the formation water in Eogene Shahejie Formation is rich in sulfate ions (SO42−), which can provide reactant for TSR reaction triggered by thermal stress from injected steam. Geochemical data including sulfur isotope of H2S, oil, sulfate, and natural gas, support the conclusion that the abundant H2S from the steam drive pilots of the Liaohe Basin are mainly originated from TSR effect under high temperature during the thermal recovery process. The observed δ34S variations lend support to the conclusion that in situ thermochemical sulfate reduction can occur during thermal recovery process. The intensity of TSR and amount of H2S occurring in pilot areas is controlled by methods of steam injection, temperature and times of treatment.

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).

Coupled Geomechanics Reservoir Simulation of UTF Phase A Project Using a Full Permeability Tensor

Abstract In this research study, we conducted a coupled thermal-stress-fluid flow numerical model on the UTF Phase A SAGD project in order to investigate the fundamental geomechanical behaviour involved in the SAGD process, and to gain insight into the reservoir response to temperature and pore pressure changes. The numerical simulation is carried out by using a self-developed coupled finite element model which incorporates our proposed strain-induced permeability model. The obtained simulation results were compared with the measured data. Introduction Thermal recovery processes involve coupling between heat transfer, multiphase flow and stress/deformation, which has become an increasingly important subject in the petroleum field(1). Particularly, the coupling is crucial in problems such as borehole stability, hydraulic fracturing and injection/production induced deformation of the ground surface during the thermal recovery process in heavy oil or oil sand reservoirs. Numerical modelling of the coupled processes is historically carried out in the areas of geomechanics modelling and reservoir simulation. The former is to compute the stress-strain behaviour; therefore, the deformation. The latter is to essentially model the multiphase flow and heat transfer in porous media. Each of these disciplines simplifies the part of the problem that is not of primary interest. These approaches are unacceptable in situations where the coupling is strong and the changes of porosity and permeability cannot be accounted for by rock compressibility alone. Gutierrez and Lewis(2) extend Biot's theory to multiphase fluid flow in deformable porous media. Based on their formulation, they conclude that the coupling between the geomechanics and the multiphase flow occurs simultaneously. Thus, fully coupled system equations of deformations, multiphase flow and heat transfer should be solved simultaneously. Development of such kinds of fully coupled geomechanics-multiphase flow-heat transfer simulators needs tremendous effort, since the existing FEM geomechanics codes and FDM reservoir simulators cannot be used. Settari and Mourits(3) present an approach to couple the stress-strain behaviour to multiphase flow-heat transfer using porosity as a coupling parameter. The geomechanics module and the thermal reservoir simulator are used in a staggered manner. Pore pressure and temperature changes are calculated from the thermal reservoir simulator and transferred to the geomechanics module. The stress and the displacement changes are then calculated in the geomechanics simulation. An iterative algorithm is used to ensure that the porosity calculated from the geomechanics module is the same as that from the thermal reservoir simulator. The staggered technique employed to solve the coupled system equations allows for the use of the existing geomechanics codes in conjunction with a standard reservoir simulator. Currently, most of the commercial coupled geomechanics-multiphase flow-heat transfer simulators are developed in this way. The disadvantage of these kinds of coupled simulators is that the thermal reservoir module, usually developed using the finite difference method (FDM), cannot accommodate the full permeability tensor, since they adopt the standard discretization scheme, such as 5-spot for 2D problems and 7-spot for 3D problems. In this paper, the development of a coupled geomechanics-multiphase flow-heat transfer simulator using the finite element method (FEM) is described with the use of Galerkin's least squares (GLS) technique(4) to stabilize the saturation equation.

Effect of Foaminess on the Performance of Solution Gas Drive in Heavy Oil Reservoirs

Abstract Some heavy oil reservoirs under solution gas drive show abnormally high final recoveries. One of the mechanisms to explain these phenomena is the foamy oil flow effect which occurs under certain operating conditions. It has been studied extensively, yet remains poorly understood and difficult to model. The objective of this work was to investigate the effect of oil foaminess on the performance of solution gas drive in heavy oil reservoirs. In this research, the first step was to find a foaming agent that will have a measurable effect on foam stability of a viscous mineral oil. A simple experimental procedure was developed to quantify the oil foaminess in the presence of an added foaming agent. Several depletion tests were conducted with the added foaming agent at different depletion rates using a two metre long sandpack. The experimental results showed that the increased foaminess of oil did not have a significant effect on the solution gas drive performance when the depletion rate was high. However, in a slow depletion test, the effect of oil foaminess was significant. Introduction With high oil prices and the continuous decline of conventional resources, attention is shifting towards heavy oil in many parts of the world. Six to nine trillion barrels, or more than two-thirds of the world's oil resources, are heavy viscous crudes that remain difficult to produce(1). Heavy oil promises to play a major role in the future of the oil industry. Therefore, understanding heavy oil behaviour and improving the recoveries in heavy oil reservoirs is crucial to meeting future energy demand. The high viscosity of heavy oils, typically in the range of 500 to 50,000 cP, results in low recovery factors in primary production. However, some Canadian heavy oil reservoirs produce more than what is expected by the conventional analogs. Primary recovery from these reservoirs could be as high as 15%(2). In conventional solution gas drive, the gas evolves in the pore space and connects with the gas in the other pores forming a free continuous gas resulting in higher gas rates. In heavy oil reservoirs, the gas bubbles tend to remain dispersed within the viscous oil because of the high viscosity, low diffusion rates and higher pressure gradients. This behaviour results in higher oil rates, lower gas-oil ratios and slower pressure decline within the reservoir. The production from this type of reservoir is usually accompanied by sand. The two-phase flow of oil and dispersed gas bubbles is usually referred to as foamy oil flow. Smith(3) appears to be the first researcher who provided an analysis to the anomalous behaviour of the heavy oil reservoirs under solution gas drive using field data. The most common techniques used to produce heavy oil from underground formations involve thermal recovery processes. However, extensive developments in Canada in the period from 1985 to 2005 have resulted in several new heavy oil exploitation technologies. One of the major new technologies in the last two decades is cold heavy oil production with sand (CHOPS)(4).

Electrical Downhole Heaters for Faja Heavy-Oil Reservoirs

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117682, "Feasibility of Using Electrical Downhole Heaters in Faja Heavy-Oil Reservoirs," by Raul Rodriguez, SPE, Jose Luis Bashbush, SPE, and Adafel Rincon, SPE, Schlumberger, originally prepared for the 2008 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 20-23 October. The paper has not been peer reviewed. The full-length paper examines use of downhole heaters in thick sands stimulating vertical and horizontal wells, evaluates temporary application of downhole heaters in horizontal wells for a limited period of time, and covers basic economic analyses. Introduction The Orinoco belt (Faja) in Venezuela contains one of the largest resources in the world of heavy and extraheavy oil. Because of the production decline of conventional light crude, projects must focus on increasing the recovery of heavy and extraheavy oils by use of thermal and nonthermal methods. Steam-based thermal-recovery processes are more efficient in low-pressure reservoirs; however, because of their depth, the initial pressures of the reservoirs in the Faja are relatively high, ranging from 600 to 1,500 psi with viscosities typically greater than 2,000 cp. For these reasons, it is important to decrease the pressure of the reservoirs with primary-production techniques to facilitate the economical implementation of steam-injection-based methods. The initial production of heavy and viscous oils can be accelerated by use of downhole heaters that, by providing energy to the vicinity of the well, decrease oil viscosity and increase the oil-production rate. A consequential advantage of using downhole heaters as a prelude to a steam-injection process is that they accelerate early production and reservoir-pressure depletion. Electrical Downhole Heaters. Electrical heating consists of providing electrical currents to generate heat and increase the temperature near the wellbore. There are two kinds of downhole heaters in use by the oil industry: inductive heaters, generating heat in accordance with Maxwell's law, and resistive heaters that generate heat in accordance with the Joule effect. In the latter case, the heat transfer is by conduction and it requires an extended time period to heat the reservoir. In this study, the resistive heater is modeled with the aid of a numerical thermal simulator. This type of heating process stimulates oil recovery primarily by reducing the oil viscosity in the near-wellbore region and secondly by thermal expansion of reservoir fluids. The key parameters to be understood in this process are the heavy-oil-viscosity variation with temperature and the rate of heat provided by the heater associated with the generated temperature gradient in the volume around the well. Heat output from resistive heaters typically ranges from 14 to 730 W/ft (1,100 to 60,000 Btu/D/ft). A maximum-exposure temperature normally is imposed on the heaters.

Residual stress field and thermal relaxation behavior of shot-peened TC4-DT titanium alloy

Shot peening is an effective surface treatment method, which can improve the fatigue properties of metallic materials. In the present paper, the residual compressive stress field induced in TC4-DT titanium alloy under different shot peening conditions and the thermal relaxation behaviors of shot-peened TC4-DT were discussed. The shot peening can cause residual compressive stress on the material surface compared to un-peened materials. The subsurface residual stress distributions of original and shot-peened specimens were measured by an X-ray diffraction method. The residual compressive stress profiles accord with the characteristic curve of residual stress field. The maximum residual compressive stress is located at subsurface layer. Surface roughness also increases with increasing shot peening intensity. There is relaxation of residual compressive stress during temperature. Thermal relaxation behavior of residual stress was studied at 150 and 300 °C with different ageing time. The residual stress relaxation is influenced by temperature and time during ageing. Thermal relaxation of residual stress is a thermal recovery process. The relaxation process of thermal residual stress is analyzed by applying the Zener–Wert–Avrami function.

A New Process Combining Cyclic Steam Stimulation and Steam-Assisted Gravity Drainage: Hybrid SAGD

Abstract A new thermal recovery scheme is proposed that utilizes Steam-Assisted Gravity Drainage (SAGD) well pairs as well as Cyclic Steam Stimulation (CSS) wells placed in between the SAGD well pairs. The wells are operated in CSS mode until the steam chambers are in contact with each other and then switched to SAGD operation. It is shown that the new process recovers greater amounts of bitumen with lower injected steam in shorter operation time than is achieved with SAGD, Fast-SAGD and CSS. Introduction Alberta's major oil sands deposits, with an estimated 1.7 trillion bbls of bitumen-in-place, account for approximately 40% of the world's bitumen resource(1). The estimated remaining recoverable bitumen from this resource is 170 billion bbls, which dwarfs the remaining conventional reserves of crude oil in Alberta by more than two orders of magnitude(2). While shallow oil sands reserves can be extracted by mining, most of these reserves (82%) are accessible through in situ thermal processes only(2). Two commercially-applied in situ production methods are Steam-Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS). These methods are technically effective but can be rendered uneconomic due to steam requirements. Although the first commercially applied thermal recovery process was CSS, there are a number of commercial and smaller SAGD projects under way at present in Alberta(3). The main attraction of SAGD compared to CSS is that higher recoveries in excess of 50% can be obtained because of the efficiency and effectiveness of the gravity drainage process. However, a challenge for SAGD is to try to promote the lateral and downward expansion of the steam chamber(4). Recently, a new process called Fast-SAGD has been proposed to overcome this problem(5–10). Fast-SAGD Process In the Fast-SAGD process, additional single offset horizontal wells are drilled in between and parallel to the SAGD well pairs. The offset wells are placed at the same elevation as the SAGD producers and can be 50 to 80 m away from the SAGD well pairs. The concept relies on operating the SAGD wells until the steam chamber reaches the top of the formation and then starting a CSS operation at the offset wells at considerably higher pressure than the SAGD wells. The purpose of injecting steam into the offset CSS well is to accelerate growth and propagation of the steam chamber laterally. Once the inter-well area between the SAGD well pairs is heated enough, ideally when the two steam chambers come into contact, the offset well is converted into a producer and the SAGD operation continues. Authors of Fast-SAGD articles reported the results of thermal numerical simulations to initially analyze the response in a Cold Lake-type reservoir and later in Athabasca- and Peace River-type reservoirs(5–10). Their numerical models were generic, two dimensional (2D) homogeneous layer cake models. Results reported were quite impressive in these idealized models where bitumen production rates increased significantly and energy efficiency, as measured by steam-oil ratio (SOR), was better compared to conventional SAGD. Given the encouraging results, it was suggested that a field test should be carried out.