Oil Sand Reservoirs Research Articles

Experimental Investigation on Dilation Mechanisms of Land-Facies Karamay Oil Sand Reservoirs under Water Injection

The success of steam-assisted gravity drainage (SAGD) is strongly dependent on the formation of a homogeneous and highly permeable zone in the land-facies Karamay oil sand reservoirs. To accomplish this, hydraulic fracturing is applied through controlled water injection to a pair of horizontal wells to create a dilation zone between the dual wells. The mechanical response of the reservoirs during this injection process, however, has remained unclear for the land-facies oil sand that has a loosely packed structure. This research conducted triaxial, permeability and scanning electron microscopy (SEM) tests on the field-collected oil sand samples. The tests evaluated the influences of the field temperature, confining stress and injection pressure on the dilation mechanisms as shear dilation and tensile parting during injection. To account for petrophysical heterogeneity, five reservoir rocks including regular oil sand, mud-rich oil sand, bitumen-rich oil sand, mudstone and sandstone were investigated. It was found that the permeability evolution in the oil sand samples subjected to shear dilation closely followed the porosity and microcrack evolutions in the shear bands. In contrast, the mudstone and sandstone samples developed distinct shear planes, which formed preferred permeation paths. Tensile parting expanded the pore space and increased the permeability of all the samples in various degrees. Based on this analysis, it is concluded that the range of injection propagation in the pay zone determines the overall quality of hydraulic fracturing, while the injection pressure must be carefully controlled. A region in a reservoir has little dilation upon injection if it remains unsaturated. Moreover, a cooling of the injected water can strengthen the dilation potential of a reservoir. Finally, it is suggested that the numerical modeling of water injection in the Karamay oil sand reservoirs must take into account the volumetric plastic strain in hydrostatic loading.

Uncertainty Analysis of Oil Sands Reservoirs Using Features in Metric Space

In oil sands reservoirs, it is difficult to predict the production reliably because a steam chamber continues to expand with time and the affected area keeps changing. This article proposes a new approach for history matching and uncertainty analysis in oil sands reservoirs. The first step is to set an area affected by the expansion of the steam chamber. Then some features are extracted and plotted in metric space using 2D discrete Fourier transform and principal component analysis. Several realizations are selected based on the same interval sampling and ranked with similar levels in production curve. The sampling weights are assigned proportional to the rankings and one realization is selected accordingly. A flow simulation performs the nearest point (realization) around the selected one in metric space. The most dissimilar realization is replaced in the candidates. The previous step is repeated until the objective function meets a stop criterion. In the result of uncertainty analysis, it could lead to a fast convergence and preserve geological reality. The mean facies map of the candidates generates successfully the position of the shale barrier in the reference field.

Hyperspectral imaging for the determination of bitumen content in Athabasca oil sands core samples

Ore grade is one of the primary variables controlling the economic recovery of bitumen from oil sands reservoirs, hence there is a need for fast and reliable quantification of total bitumen content (TBC). This is typically achieved through laboratory-based Dean-Stark analyses of drill core samples. However, this method is time and labor intensive and destructive to the core sample. Hyperspectral imaging is a remote sensing technique that can be defined as reflectance spectroscopy with a spatial context, where high-resolution digital imagery (∼1 mm/pixel [0.04 in./pixel]) is acquired and reflectance measurements are collected in each pixel of the image. This study compares two hyperspectral models for the determination of TBC from imagery of both fresh and dry core samples. For three out of four suites of fresh core, TBC was predicted within ±1.5 wt. % of the Dean-Stark data with both spectral models achieving correlations of . For a fourth fresh core and the dry core, larger margins of error were found because of some instances of overestimation. Surface roughness because of uneven oil distribution and small-scale fracturing is a potential source of error in some of the spectral TBC results, particularly for the dry core. Producing results within minutes with the additional benefit of being nondestructive to the core sample, hyperspectral imaging shows great potential to become a viable alternative method for bitumen content determination in oil sands.

A correlation of steam chamber size and temperature falloff in the early-period of the SAGD Process

Steam Assisted Gravity Drainage (SAGD) is a widely-used thermal oil recovery technique in western Alberta’s oil sands reservoirs. Because of reservoir heterogeneity, the wellbore hydraulics and undulation, non-uniform steam chambers will evolve. Numerical simulation allows for the practical prediction of steam chamber size in SAGD. However, the long computation time in 3D scenarios and the impact of uncertainties in input parameters limit its application.In this paper, a numerical simulation based correlation between steam chamber size and temperature falloff data during shut-in was developed in the early period of the SAGD process which is before the moment that the steam chamber starts spreading laterally. The temperature falloff responses and the corresponding steam chamber sizes at different locations in the producer along the lateral were obtained though 3D numerical simulation studies. Based on the simulation results, a correlation among steam chamber, the temperature falloff rate and the height of liquid level in the producer was derived through regression analysis. The same correlation equation with different coefficients was also found at different shut-in times. The applicability of the proposed correlation in estimating steam chamber sizes along horizontal well is also investigated and validated. A synthetic case study shows that the chamber sizes obtained from the correlation and from simulation are in good agreement and also suggests that this correlation is applicable to estimate the chamber size distribution along the horizontal well at the early period of SAGD process.

Radio Frequency heating for oil recovery and soil remediation

The paper presents basic principles of RF heating and describes its possible applications for oil extraction and soil remediation, based on the experience obtained by several years of work at Consorzio Polo Tecnologico Magona (CPTM). Activities include a complete approach, which goes through the steps of problem formulation, modeling, and experimentation. It is shown that RF heating can represent a valid alternative to more consolidated techniques for application to oil extraction from oil sand or heavy oil reservoirs and for organic polluted soil remediation, in terms of performances and operational flexibility. In particular, radiofrequency heating can be used in several scenarios where the use of alternative methods (such as steam injection) is not possible or strongly limited by geological or logistic constraints.

Model-Predictive-Control (MPC) of Steam Trap Subcool in Steam-Assisted Gravity Drainage (SAGD)

For thermal technologies for heavy oil and oil sand reservoir extraction, such as cyclic steam stimulation and steam-assisted gravity drainage (SAGD), suboptimal steam conformance leads to recovery factors between 25-50%. Although preliminary research using Proportional-Integral-Derivative (PID) control in SAGD operations has proved beneficial towards steam conformance, PID control is responsive only to deviation from set-points and lacks constraint-handling capabilities. This results in suboptimal actuation signals that are sometimes unattainable. This paper summarizes research on a Model-Predictive-Controller (MPC) with proactive adjustments of steam injection rate. The steam injection rate was determined based on recursive parameter updates of a suitable time varying dynamic model describing the implicit relationship between the subcool temperature difference and the input heat rate, to achieve optimal steam conformance. Furthermore, the steam injection rate was constrained such that the pressure with which the steam impinged on the formation, called well bottom hole pressure (BHP), was below the formation fracture pressure of 4500 kPa at all times. The real time control study was made possible by establishing a bidirectional communication link between the Computer Modelling Group (CMG) STARS™, and MATLAB/Simulink software. The three-dimensional heterogeneous reservoir model, developed in STARS™ acted as a virtual plant and the MPC, developed in MATLAB/Simulink, acted as an onsite controller. Results show 35.7% improvement in oil recovery and a more efficient cumulative steam-to-oil ratio (cSOR) profile in comparison to the base case of steam injection at a constant BHP of 4000 kPa.

Feasibility Study of "Fracture network" Fracturing Technique Applied to the Fissured Competent Sand Oil Reservoir and Field Test

Chang 8 oil deposit, developed in Hohe oil field at the southern Yi-Shan Slop of Ordos Basin, is regarded as a kind of typical sand reservoir formation with super-low porosity, poor permeability, strong anisotropy as well as locally natural faults and fractures. Matrix reservoir has a poor permeability, but fracture reservoir has a reverse manner. In the past years, fewer researchers paid their attentions to study matrix-fracture type oil reservoir, therefore today it is still difficult to identify whether network hydraulic fracturing can be effectively exploited in low permeable matrix-fracture type reservoir. In this paper, the author tries to analyze the feasibility of network hydraulic fracturing application in Chang 8 oil deposit from following aspects: mineral component, rock brittleness index, development status of natural fractures, ground stress and net press during hydraulic fracturing. The statistical results indicate that the geological condition of research object is confirmed to meet the standard of hydraulic fracturing with medium brittleness index, high angle, developed natural fracture and horizontal layers as well as the difference of two principal horizontal stresses 5.4 MPa. The paper performed field investigation in HH6P2 well by the methods of segmental perforation, interference between multiple clusters and boosting net pressure. Then its daily output was up to 2.58 t. Finally, the paper

Features Modeling of Oil Sands Reservoirs in Metric Space

Uncertainty in oil sands reservoirs can be quantified by generating multiple realizations using geostatistical methods. However, it requires huge computing time to simulate all of the realizations. This article proposes a new approach for features modeling of oil sands reservoirs in metric space. As the first step, an area affected by the expansion of a steam chamber is set and converted to the polar coordinate system. The converted area is expressed as an image matrix consisting of 0 or 1 value. Then the matrix is transformed using two-dimensional discrete Fourier transform. Key features in the front columns and rows of the transformed matrix are extracted. These features in metric space are plotted using principal component analysis. Self-organizing map algorithm is used to select representative models of realizations for performing full flow simulations. In the result of grouping, each cluster group distributes separately in metric space according to reservoir productivity, but there are mixes of a small portion among the adjacent groups due to similar productivity.

Incorporating 3C seismic data quantitatively for enhanced geologic detail in an oil sands reservoir

A workflow incorporating converted-wave (PS) data in an integrated quantitative interpretation (QI) was illustrated with a case study in the Canadian oil sands in which multiple data types were available including high-quality 3D multicomponent data, dipole sonic logs, and a multicomponent walk-away vertical seismic profile (VSP). In an area with unconventional rock property behavior and complex fluid distributions, the dipole sonic logs provided the data necessary for robust deterministic rock-physics templates. The VSP was essential in depth-registering the P-wave surface seismic with the PS-wave data and in determining the appropriate phase rotation of each data set. The 3D multicomponent seismic was used to derive a variety of separate and joint attributes incorporating amplitude variation with offset, prestack and poststack inversion and multiattribute processes. Finally, all elements of the workflow were combined in an interactive classification procedure for optimum representation of geology in the seismic volume. Results of the QI workflow with and without the PS data were compared with each other, and ultimately, to blind wells to assess the potential benefits of including PS data. The comparison showed that better prediction of fluid properties, without compromising P-wave data resolution, was possible when PS data were included.

Determination of the stable isotope composition and total dissolved solids of Athabasca oil sands reservoir porewater: Part 1. A new tool for aqueous fluid characterization in oil sands reservoirs

We present a new method to determine the total dissolved solids (TDS) concentration and the stable isotope composition of drill-core-derived Porewater in oil sands reservoirs of northeastern Alberta, Canada. The technique described here uses two end-member mixing relationships between the stable isotope compositions of drilling fluids and formation waters from mechanically extracted porewater samples to calculate the formation water TDS, , and values. Analysis of water samples extracted directly from McMurray Formation drill core provides an inexpensive and robust advance in the ability to characterize the properties of reservoir pore waters that can be widely deployed because of the ubiquity of drill-core sampling. Porewater data from three oil sands wells from different locations within the Athabasca region are presented in this study. Water derived from these wells had TDS values of 860 to 45,000 mg/L, values of −172 to −149‰, and values of −22.4 to −19.3‰. These values are consistent with regional trends in formation water salinity and stable isotope compositions, and illustrate the wide range of TDS values that can be found in McMurray Formation waters. The ability to characterize aqueous fluids within bitumen-saturated reservoirs is a new development that enables measurement of aqueous fluid properties that is not easily obtained by other sampling means. This methodology provides a tool to understand the origin and movement of reservoir water related to natural groundwater flow, or to anthropogenic influence by steam injection. Novel in situ extraction technologies that use electromagnetic heating systems may also benefit from detailed characterization of aqueous reservoir fluids to accurately determine the properties of the reservoir porewater.

A case study of multipole acoustic logging in heavy oil sand reservoirs

The multipole acoustic logging tool (MPAL) was tested in the heavy oil sand reservoirs of Canada. Compared with near shales, the P-wave slowness of heavy oil sands does not change obviously, with the value of about 125μs/ft; the dipole shear slowness decreases significantly to 275μs/ft. The heavy oil sands have a Vp/Vs value of less than 2.4. The slowness and amplitude of dipole shear wave are good lithology discriminators that have great differences between heavy oil sands and shales. The heavy oil sand reservoirs are anisotropic. The crossover phenomenon in the fast and slow dipole shear wave dispersion curves indicates that the anisotropy is induced by unbalanced horizontal stress in the region.

Determination of the stable isotope composition and total dissolved solids of Athabasca oil sands reservoir porewater: Part 2. Characterization of McMurray Formation waters in the Suncor–Firebag field

A new stable isotope approach was used to determine the total dissolved solids concentration and stable isotope composition for oil sands drill core extracted porewater at the Suncor–Firebag oil sands field in northeastern Alberta, Canada. A stable isotope mixing approach was used to correct for contamination by drilling fluids in the porewater samples. The mean isotopic compositions of oxygen () and hydrogen () in water for fluid samples from 12 wells at Firebag were −20.5 ± 1.4‰ and −157 ± 11‰, respectively. The mean total dissolved solids (TDS) concentration of the reservoir formation water in 12 sampled wells was 1100 ± 400 mg/L (1σ). These results suggest that the McMurray Formation water at Firebag is primarily derived from Holocene groundwater recharge, and that the water within the bitumen reservoir is similar to groundwater well samples obtained within the McMurray Formation at Firebag. The results obtained in this study are consistent with regional trends and previously proposed local hydrogeological flow conditions.

Anomalous surface heave induced by enhanced oil recovery in northern Alberta: InSAR observations and numerical modeling

AbstractRecent interferometric synthetic aperture radar observations over northern Alberta, Canada, show persistent surface heave occurring at rates of 1–4 cm/yr, localized at sites where the steam‐assisted gravity drainage technique is currently used to extract bitumen from the Athabasca oil sands. We find that uplift rates above the horizontal injector wells are strongly correlated with rates of steam injection, even though there is a net fluid loss from the reservoir pore space as oil and water are withdrawn through the production wells. In combination with available steam injection and bitumen production data at four sites, we use reservoir flow models to explain how the thermal and geomechanical effects of steam injection on an oil sand reservoir can generate uplift at the surface. Results of our numerical experiments show that persistent surface heave consistent with observed rates can be driven by stress changes in the reservoir due to porous flow and thermal expansion. We also observe an unexpected localized uplift, of magnitude equal to or greater than the heave above the sites of steaming but located at clusters of wellheads which are outside the region of influence of the steam chambers. We show that this “wellhead” deformation can be explained by thermal expansion of rock near the injector wells.

Magnetic susceptibility and its relation with fractures and petrophysical parameters in the tight sand oil reservoir of Hamra quartzites, southwest of the Hassi Messaoud oil field, Algeria

Abstract Magnetic susceptibility (Ms) measurements were carried out in the cores of six wells distributed throughout the study area of tight sand oil of the Hamra quartzites reservoir, southwest of the Hassi Messaoud oil field. With steps of 2 cm, 8760 Ms values were taken from a total core length of 174 m. In most of the intervals, the contrasts in Ms coincide with high fracture density and high shale content (increase of gamma ray in this interval). The analysis of the hysteresis loops, isothermal remanent magnetizations to saturation (IRMs) and thermomagnetic curves for samples taken from some high interval of Ms shows that magnetite and pyrrhotite are the main magnetic minerals. It demonstrates that fractures can be considered as precipitation environments of the magnetic minerals in the reservoir, which is a good indicator for mineralized fractures. The application of principal component analysis (PCA) to the entire reservoir shows low linear correlation between Ms and the main petrophysical parameters (gamma ray, neutron porosity, density, and saturation of oil). Meanwhile, the application of fuzzy ranking and artificial neural network (ANN) evidenced non-linear relations between these parameters. It is justified by the prediction of the Ms from the petrophysical parameters with an acceptable degree of accuracy. The results obtained using an ANN structure of 25 neurons in a hidden layer show the performance in the test stage with mean square error (MSE), mean relative error (MRE) and correlation coefficient (R) equal to 0.0142, 0.0743 and 0.907, respectively.

고온 고압 스팀을 주입하는 SAGD 공정에서 CO2주입이 오일샌드 역청 회수율에 미치는 영향

오일샌드에서 비투맨(bitumen)을 회수하는 지하회수방식 중 가장 많이 사용하는 기술인 SAGD (steam assisted gravity drainage)공정으로부터 비투맨의 회수율을 향상시키고자 스팀과 함께 주입한 첨가제의 효과와 매커니즘에 대해서 연구하였다. 실제 광구에서 쓰이는 SAGD공정을 150 : 1로 축소한 실험실 규모의 모사장비가 사용되었으며, 지하 박층을 모사할 수 있는 장치(이하 GM, geological model)가 사용되었다. 초중질유와 글래스비드(glass bead 1.5 mm)의 혼합물은 오일샌드의 모사재료로 사용되었다. 첨가제로서 <TEX>$CO_2$</TEX>가 사용되었으며, 스팀 챔버(steam chamber)의 성장 변화를 비교 분석하였다. <TEX>$CO_2$</TEX>의 주입방식에 따른 효과를 확인하기 위하여 스팀과 <TEX>$CO_2$</TEX>를 연속 주입하는 실험(<TEX>$cCO_2$</TEX>-SAGD)과 순차적으로 주입하는 실험(<TEX>$sCO_2$</TEX>-SAGD)을 실시하였다. 그 결과 <TEX>$sCO_2$</TEX>-SAGD 실험의 경우 Control 실험 대비 오일 회수율은 60.2%에서 69.3%로 향상되었으며 cSOR의 경우 7.1에서 6.0으로 낮아졌다. 반면에 <TEX>$cCO_2$</TEX>-SAGD 실험의 경우 60.2%에서 57.6%, 7.1에서 7.3으로 증가 되었다. SAGD (steam assisted gravity drainage) process is the most commonly used in-situ technology for the recovery of bitumen from oil sand. It was investigated that the effects of different additives on bitumen recovery rate from oil sand in SAGD process among many possible mechanisms studied throughout the study. Bitumen recovery from thin layer oil sand reservoirs was simulated by using an experimental SAGD apparatus with scale of 150:1. To improve the simulation accuracy of thin layer oil reservoir, we have attached geological model (GM). Oil sand was simulated by using a mixture of extra heavy oil and glass beads with a diameter of 1.5 mm. <TEX>$CO_2$</TEX> was used as an additive and the evolution of steam chambers were closely monitored, and the effects of <TEX>$CO_2$</TEX> as an additive was investigated. Two types of injection methods were tested; continuous (<TEX>$cCO_2$</TEX>-SAGD) and sequential interruption (<TEX>$sCO_2$</TEX>-SAGD) <TEX>$CO_2$</TEX> injection. For the <TEX>$sCO_2$</TEX>-SAGD experiment, it was observed that the recovery rates and CSOR were efficiently improved control experiment from 60.2% to 69.3% and 7.1 to 6.0, respectively, whereas <TEX>$cCO_2$</TEX>-SAGD experiment decreased from 60.2% to 57.6% and 7.1 to 7.3.

Journal of Petroleum and Gas Exploration Research

Oilsand in China is very rich, especially in northwestern Sichuan basin. Houba oilsand is one of the famous oilsand belts, it consists of medium-coarse grained sandstone with high porosity and permeability. The genesis of those pores is very important in the research of Houba oilsand reservoir. Based on thin section analyses, SEM observation and X-ray diffraction (XRD) analysis, the diagenesis and pore evolution of oilsand reservoir have been studied. It shows oilsand reservoir in Shaximiao Formation had experienced the early diagenesis and the late diagenesis including early mechanical compaction, four times cementation and two times dissolution. Diagenetic alterations affect the pore evolution in the long geology history. At last, porosity evolution model of the oilsand reservoir have been established.

Lithofacies distribution and depositional environment in the Lower Cretaceous McMurray Formation, BlackGold Lease, northern Alberta: implications for geometry and distribution of oil sand reservoirs

Within BlackGold Lease located in northern Alberta, the Lower Cretaceous McMurray Formation contains the most prolific bitumen reservoirs deposited in fluvial to tidally-influenced estuarine environments. Based on core descriptions and wire-line log evaluation, this study reveals six lithofacies: cross-stratified sandstone and mudstone-clast breccia (Lf1), sandstone-dominated IHS (Lf2), mudstone-dominated IHS (Lf3), thinly interbedded sandstone and mudstone (Lf4), laminated mudstone (Lf5), and clean sandstone with interbedded mudstone (Lf6). To understand the evolution of depositional environments vertical and lateral associations of lithofacies are examined using well cross-sections and lithofacies slice maps. During overall rise in relative sea level, the McMurray Formation evolved through three stages of deposition: early stage represents fluvial channels with minor tidal influence, middle stage represents tidally-influenced estuary with well-developed meandering channels, and late stage represents a drowning of tidally-influenced estuary. The potential bitumen reservoirs are fluvial channel sandstones in the early stage and lower point-bar deposits in the middle stage. The fluvial channel sandstones are well stacked and correlatable between wells, forming sheet-like sandstone bodies that align in a SW-NE direction parallel to the inferred orientation of major channel systems. The lower point-bar deposits consist mainly of base-of-channel and sandstone-dominated IHS deposits. The direction of point-bar migration, which is crucial in horizontal well design for bitumen production, is inferred from lithofacies slice maps. The lateral changes in lithofacies from base-of-channel to abandoned channel-fills through IHS deposits, shown in lithofacies slice maps, probably indicate that the point bar once migrated toward abandoned channel-fills. Based on this lateral lithofacies trend, the dip direction of some point-bar deposits are approximately estimated to be southwestward or northwestward, which is oblique or perpendicular to the major channel orientation.

Application of Toyota's Principles and Lean Processes to Reservoir Management: More Tools To Overload the Toolbox or a Step Change in Our Business?

SummaryAera Energy LLC was formed in 1997 to be a low-cost operator and producer in California. However, the low oil prices from 1998 to 1999 forced an examination of all operations in the office and in the field. Cutting costs, improving timekeeping, or reducing the scale of operations would not be sufficient without a step-change gain in efficiency. This step-change gain came from the use of principles and concepts developed in the automobile and construction industries. Toyota's twin pillars of just-in-time production and the ability of anyone to stop production rather than pass on defects, coupled with level-loading of work processes and reducing waste, were introduced. Toyota's principles were enhanced by the addition of “Last Planner” concepts developed for the construction industry. When both were implemented for reservoir-characterization and reservoir-development work, significant process improvements resulted. The resulting improvements are now being used throughout the company to improve quality by removing waste and reducing errors, to measure processes, and to improve cycle times.The unconventional diatomite reservoirs and oil-sand reservoirs at the giant Belridge field produce 65,000 BOPD from 5,300 producing wells and 2,100 injection wells. The many drilling, completion, and workover rigs have a constant appetite for new wells. To maintain production and cost targets, everything in the office has to run reliably and efficiently at all times, as well as support field operations.Different aspects of Toyota's principles and “Lean Manufacturing” are illustrated by use of project work for reservoir characterization, day-to-day reservoir surveillance, and the development work needed to plan and schedule new wells. The processes and projects typically have multiple customers and suppliers—internal and external. All involved, including knowledge workers (those who think for a living), need to work as a single system with a manufacturing mentality and to strive for continuous improvement. Customers of the knowledge work supplied by the geoscientists and reservoir engineers have benefited greatly from the introduction of the lean processes and the resulting smoother and more-effective workflows. In 2011, the Development Team's lean activities were recognized by the Association for Manufacturing Excellence, and the team received the Manufacturing Excellence Award that recognizes “continuous improvement, best practices, creativity, and innovation.”The oil industry has a reputation of being slow to adopt new technologies and techniques. However, a Lean Manufacturing mentality introduces new ideas and ways of performing knowledge work that may change this paradigm while contributing to the bottom line with reduced cycle time and improved quality. A significant additional benefit is that geoscience and engineering professionals can spend more time doing creative work and less time fixing problems or reacting to system upsets—as they simultaneously reduce waste. However, to realize all these benefits and the step changes they provide, a thorough understanding of Toyota's principles and a Lean Manufacturing mentality are essential.

Orientation of a pad of SAGD well pairs in an Athabasca point bar deposit affects performance

It has been shown that the performance of a Steam-Assisted Gravity Drainage (SAGD) well pair is affected by its orientation and position within a point bar deposit. In typical commercial operations, multiple horizontal wellpairs, usually arranged parallel to each other, are arranged in pads within oil sands reservoirs. Thus, the overall performance of the recovery process in a point bar is not represented by a single well pair but how the set of well pairs interact with the structure and geometry of the point bar notably including the arrangement of inclined heterolithic strata relative to the SAGD well pairs. This research describes how the point bar structure impacts the performance of a pad of SAGD wellpairs and the impact of pad orientation on performance of the pad. Also, the results show that the variability of the performance of the well pairs within the pad is large and thus, single well pair models do not provide sufficient analysis of the SAGD process performance due to the heterogeneity of the point bar. In other words, pad-scale models are required for recovery process evaluation and design. Furthermore, the variability of performance obtained from the models provides an estimate of the variability that may result for systems where seismic data is not available or is not sufficient to fully characterize the point bar.

エマルション生成, CO&lt;sub&gt;2&lt;/sub&gt;フォーミィオイル生成および原位置燃焼による重質油の生産挙動について

Enhanced oil recovery (EOR) processes have been applied to improve mobility of heavy oil and bitumen. This article has introduced three topics on numerical models for heavy oil and bitumen productions based on laboratory measurements and their scaling up to field reservoir simulations using CMG STARS™.First one is CO2 gas foaming by depressurizing after immiscible CO2 dissolution in heavy oil. Saturated CO2 solubility and apparent swelling after foaming were measured on decreasing pressure processes using PVT apparatus and a high pressure cell. The numerical models of apparent viscosity and swelling ratio for foamy heavy oil have been proposed based on the measurement data and applied to a field scale oil-reservoir by Huff-n-Puff production methodThe second one is bitumen emulsion (water in oil) formed by the Steam Assisted Gravity Drainage (SAGD) method for oil-sands layers, because condensed fine water-droplets diffuse into bitumen at the steam-chamber boundary. The characteristic of heavy-oil viscosity was measured against water/oil ratio (W/O) and temperature. The model of viscosity ratio (emulsion/original) vs. W/O has been presented and investigated its effect on bitumen-production from a typical oilsands reservoir by SAGD method. Finally, it has been shown that cumulative bitumen-production increases with bitumen swelling function of W/O.The third one is heavy oil recovery by in-situ combustion with injecting air or O2 gas. Recently, the Toe-to-Heal Air Injection (THAI) method using a vertical injector and a horizontal producer is expected to be able to keep stable combustion front and oil drainage flow into the producer. Based on our numerical history-matching study on the tube combustion test for bitumen sands-pack, the reaction model consists from 3 major reactions were screened from 8 chemical reactions on Maltenes, Asphaltenes and Coke. Finally, the model was successfully applied to a heavy-oil in-situ production from a typical field oil reservoir.