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Collaborating Authors
Results
Summary Our studies of the underlying fundamental gas-recovery mechanisms from shale gas are motivated by expectations of the increasing role of shale gas in national energy portfolios worldwide. We use pore-scale analysis of reservoir shale samples to identify critical parameters to be employed in a gas-flow model used to evaluate well-production data. We exploit a number of 3D-imaging technologies to study the complexity of shale pore structure: from low-resolution X-ray computed tomography (CT) to focused ion beam and scanning electron microscopy (FIB/SEM). We observe that heterogeneity is present at all scales. The CT data show fractures, thin layers, and density heterogeneity. The nanometer-scale-resolution FIB/SEM images show that various mineral inclusions, clays, and organic matter are dispersed within a volume of few-hundred µm. Samples from different regions differ sharply in the shape, size, and distribution of pores, solid grains, and the presence of organic matter. Although the samples have clearly distinguishable signatures related to the regions of origin, extremely low permeability is a common feature. This and other pore-scale observations suggest a bounded-stimulated-domain model of a horizontal well within fractured shale that accounts for both compression and adsorption gas storage. Using the method of integral relations, we obtain an analytical formula approximating the solution to the pseudopressure diffusion equation. This formula makes fast and simple evaluation of well production possible without resorting to complex computations. It ss a decline curve, which predicts two stages of production. During the early stage, the production rate declines with the reciprocal of the square root of time, whereas later, the rate declines exponentially. The model has been verified by successfully matching monthly production data from a number of shale-gas wells collected over several years of operation. With appropriate scaling, the data from multiple wells collapse on a single type curve. Pore-scale image analysis and the mesoscale model suggest a dimensionless adsorption-storage factor (ASF) to characterize the relative contributions of compression and adsorption gas storage.
- Europe (1.00)
- North America > United States > Texas (0.46)
- North America > United States > California (0.28)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Kentucky > Illinois Basin > New Albany Shale Formation (0.99)
- North America > United States > Indiana > Illinois Basin > New Albany Shale Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Summary This paper presents a simplified method of production forecasting for tight/shale-gas reservoirs exhibiting extended periods of linear flow, without the use of complex tools (e.g., analytical models or numerical models). The method, which is applicable to hydraulically fractured vertical wells and multifractured horizontal wells, is simple because it relies principally on a plot of inverse rate vs. square root of time, and it is rigorous in that it is based on the theory of linear flow and combines the transient linear-flow period with hyperbolic decline during boundary-dominated flow. The dominant flow regime observed in most tight/shale-gas wells is linear flow, which may continue for several years. This linear flow will be followed by boundary-dominated flow at later times. Therefore, the method proposed in this study is applicable for forecasting production data for these wells because it considers these two important flow regimes. The derivation is presented for a hydraulically fractured well, and this simplified method can be applied both to hydraulically fractured vertical wells and to horizontal wells with multiple fractures. The application of this method to multifractured horizontal wells in the Marcellus and Barnett shale gas is also presented. The method is validated by comparing its results with test cases, which are built using numerical simulation for hydraulically fractured vertical wells. For each case, only the first year of the synthetic production data is then used for the analysis. It is found that there is reasonable agreement between the forecast rates obtained using this method and the numerically simulated rates. Currently, analysis techniques using material-balance time are being used in industry to analyze tight/shale-gas reservoirs. Because material-balance time is actually boundary-dominated flow superposition time, these analyses may show symptoms of boundary-dominated flow even though the reservoir is still in transient flow. The advantages of the forecasting method proposed in this study are that: (1) it is not biased toward any flow regimes because no superposition time functions are used; (2) reliable forecasts can be obtained without using pseudotime--this is an advantage because using pseudotime introduces complexities and an iterative procedure; and (3) the only major unknown is the drainage area.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (0.93)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Overton Field (0.99)
- (9 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
A Comparative Study on WAS, SWAS, and Solvent-Soak Scenarios Applied to Heavy-Oil Reservoirs Using Five-Spot Glass Micromodels
Farzaneh, Seyed Amir (Heriot-Watt University) | Dehghan, Ali Akbar (Sharif University of Technology) | Ghazanfari, Mohammad H. (Sharif University of Technology) | Kharrat, Riyaz (Petroleum University of Technology)
Summary In this work, a series of solvent- and water-injection scenarios were conducted on horizontal five-spot glass micromodels that were saturated initially with heavy oil. Sandstone and limestone rock look-alike and network patterns with different pore structures were used in the experiments. The results show that the ultimate oil recovery of a water-alternating-solvent (WAS) scheme was greater than that of a simultaneously water-alternating-solvent (SWAS) scheme, and the efficiency of a solvent-soak scheme also offers a greater recovery. Likewise, the WAS scheme resulted in greater oil recovery when compared with continuous solvent injection (CSI), with the same amount of solvent consumption. Furthermore, some pore-scale phenomena, such as viscous fingering, diffusion of solvents into heavy oil, and localized entrapment of oil and solvent because of heterogeneity and/or water blockage, are also illustrated. The results of this work can be helpful for better understanding and verification of flow transport and pore-scale events during different solvent-based-injection scenarios in heavy-oil reservoirs.
- North America > United States (1.00)
- Asia > Middle East > Iran (0.69)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Summary This paper presents a numerical model to study the onset and rate of sand production and compares its predictions against physical-model testing data on Salt Wash South (SWS) sandstone. A reliable sand-prediction tool is essential in sand-production management. It enables engineers to improve well-completion design, with the aim of maximizing well productivity without compromising well integrity. A sanding test on a weakly consolidated sandstone sample was numerically simulated using a finite-difference-based numerical model. The model is based on erosional mechanics in which coupling between fluid flow and mechanical deformation captures some of the key mechanisms that are involved in sand production. Sand is assumed to be produced when the material is fully degraded and hydrodynamic forces are high enough to remove the particles. The outcome of the numerical model shows a reasonable agreement against perforation-test results in terms of the onset and rate of sand production. The model shows that sand production initiates from the perforation tip and propagates to the top and sides of the perforation cavity. The sanding rate increases at higher flow rates. Furthermore, the model predicts external deformations of the sample, which are in close agreement with the experimental observations.
- North America > United States (1.00)
- North America > Canada > Alberta (0.16)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.70)
- Geology > Geological Subdiscipline > Geomechanics (0.47)
- Well Completion > Sand Control (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
Summary The acoustic-wave-detection system is considered a nondestructive monitoring system to estimate distances by measuring the time-of-flight of an ultrasonic wave. In this paper, a comprehensive experimental study was conducted to investigate the feasibility of the acoustic-wave-detection system in monitoring the shape and position of the gas phase in the vapour-extraction (VAPEX) process. For this purpose, various stages of vapour-chamber evolution in the VAPEX process were simulated experimentally by changing the shape of air balloons buried in simulated porous media in a laboratory-scale model. Then, an array of ultrasound transducers and receivers was used to measure time of flight at different stages of the vapour-chamber growth. Finally, the collected data were fed into a signal-processing program developed in this study to determine the shape of the vapour chamber. Conducted analysis in this study includes sound-speed testing in different porous media, signal-attenuation tests in different porous media, imaging of different simulated vapour chambers in different porous media, and acquisition and analysis experiments. Results show that acoustic-wave detection can be used for accurate mapping of the position and shape of the vapour chamber in the studied process. Monitoring the shape and growth of the vapour chamber provides valuable information for optimizing oil production in order to maximize oil recovery. The proposed methodology is able to identify acoustic anomalies in a porous medium in the laboratory.
- Asia (1.00)
- North America > Canada > Alberta (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Rock Type (0.94)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.68)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (0.47)
Summary The commercial viability of the steam-assisted gravity-drainage (SAGD) process is affected negatively by several undesirable reservoir features, such as pronounced heterogeneity, low vertical permeability, thick and areally extensive shale barriers, and steam thief zones. The efficiency of SAGD projects is also affected by the presence of higher water saturation in the target zone. Although the presence of small mobile-water saturation is not considered harmful, reservoirs with high water saturation may be poorly suited for the SAGD process. Nonetheless, SAGD remains the only practical technology for in-situ extraction of oil from oil-sand reservoirs, even when mobile water is present. This raises the question of how much mobile water is prohibitive. To investigate the effect of water saturation on SAGD performance, high-pressure physical-model experiments were carried out. Different levels of water saturations were established in the model by modifying the packing and saturating techniques. SAGD experiments were carried out by injecting superheated steam at controlled rates and producing the oil from the production well at constant pressure. The injection rate was selected to keep the pressure difference between the injector and the producer at a low level. The oil-production behavior was analyzed to evaluate the effect of water saturation on the thermal efficiency of the process. On the basis of the results of low- (immobile) and high- (mobile) water-saturation experiments, it was observed that the oil-recovery factor dropped by 6.6% when the initial water saturation was increased from 14.7% to 31.8%.
- Asia (0.67)
- North America > Canada > Alberta (0.16)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.34)
Summary For stratified reservoirs with free crossflow and where fractures do not cause severe channeling, improved sweep is often needed after water breakthrough. For moderately viscous oils, polymer flooding is an option for this type of reservoir. However, in recent years, an in-depth profile-modification method has been commercialized in which a block is placed in the high-permeability zone(s). This sophisticated idea requires that (1) the blocking agent have a low viscosity (ideally a unit-mobility displacement) during placement, that (2) the rear of the blocking-agent bank in the high-permeability zone(s) outrun the front of the blocking-agent bank in adjacent less-permeable zones, and that (3) an effective block to flow form at the appropriate location in the high-permeability zone(s). Achieving these objectives is challenging but has been accomplished in at least one field test. This paper investigates when this in-depth profile-modification process is a superior choice over conventional polymer flooding. Using simulation and analytical studies, we examined oil-recovery efficiency for the two processes as a function of (1) permeability contrast, (2) relative zone thickness, (3) oil viscosity, (4) polymer-solution viscosity, (5) polymer- or blocking-agent-bank size, and (6) relative costs for polymer vs. blocking agent. The results reveal that in-depth profile modification is most appropriate for high permeability contrasts (e.g., 10:1), high thickness ratios (e.g., less-permeable zones being 10 times thicker than high-permeability zones), and relatively low oil viscosities. Because of the high cost of the blocking agent relative to conventional polymers, economics favors small blocking-agent-bank sizes (e.g., 5% of the pore volume in the high-permeability layer). Even though short-term economics may favor in-depth profile modification, ultimate recovery may be considerably less than from a traditional polymer flood.
- North America > United States > Texas (0.46)
- Asia > China > Heilongjiang Province (0.28)
- North America > United States > Alaska > North Slope Borough (0.28)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > Kuparuk Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- (3 more...)
Technology Options and Integration Concepts for Implementing CO2 Capture in Oil-Sands Operations
Ordorica-Garcia, Guillermo (Alberta Innovates - Technology Futures) | Nikoo, Mehrdokt (Alberta Innovates - Technology Futures) | Carbo, Michiel (Energy Research Centre of the Netherlands) | Bolea, Irene (Universidad de Zaragoza)
Summary The majority of the technology development for CO2 capture and storage (CCS) is driven by the electric-utility industry, in which the emphasis is on large centralized units for electric-power generation with coal as the primary fuel. The implementation of CCS in oil-sands operations has significant potential to provide meaningful carbon-emissions reductions. This paper presents various concepts for integrating leading CO2-capture techniques to bitumen-extraction and -upgrading processes. The main carbon-capture technologies are reviewed, and their relative advantages and disadvantages for implementation in bitumen mining, thermal bitumen extraction, and bitumen upgrading are discussed, leading to a qualitative assessment of their suitability for each oil-sands process.
- Europe (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.46)
- North America > United States > California (0.28)
- Research Report (0.46)
- Overview (0.46)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Madison Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Forbisher Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Charles Formation:Middale Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- (3 more...)
Summary Air-injection-based recovery processes are receiving increased interest because of their high recovery potentials and applicability to a wide range of reservoirs. However, most operators require a certain level of confidence in the potential recovery from these (or any) processes before committing resources, which can be achieved with the use of numerical reservoir simulation. In a previous paper, (Gutiérrez et al. 2009) it was proposed that after successful laboratory testing, analytical calculations and semiquantitative simulation models would be used for pilot design and further optimization of the actual operation. However, the specific steps for building the field-scale-simulation models were not addressed explicitly. This paper discusses a detailed workflow that can be followed to engineer an air-injection project using thermal reservoir simulation. The first step of the simulation study involves the selection of a kinetic model that either can be developed specifically for the reservoir in question or taken from public literature. Second, the oil would be characterized in terms of the same pseudocomponents employed by the kinetic model, and relevant pressure/volume/temperature (PVT) data would be matched to develop a fluid model for the thermal simulator. This new fluid model is used in the field-scale-simulation model to history match the production history (i.e., before air injection) of the field. Third, relevant combustion-tube tests would be history matched to validate the kinetic model and refine the thermal data that would be entered into the field-scale model. Finally, the results and knowledge gained from the combustion-tube match(es) are applied to the field-scale model with the proper upscaling of some parameters. This simulation model would aid in selecting optimum well locations and operating strategies of the pilot. It would then be refined as the actual operation progresses to enhance its predictability and allow further optimization of the project. Technical considerations, advantages, and limitations of each step of the workflow are discussed in detail. This paper also presents workflow variations and recommendations applicable to new and already-mature air-injection projects for which simulation models are being developed.
- North America > United States (1.00)
- Europe (1.00)
- South America (0.92)
- (2 more...)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.96)
- Geology > Geological Subdiscipline (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- South America > Argentina > Mendoza > Cuyana Basin > Barrancas Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Mordovo Karmalskoye Field (0.99)
- (4 more...)
Summary In-situ extraction of ultraviscous deposits from the vast bitumen resources in western Alberta, Canada, requires significant water and energy usage, which consequently leads to greenhouse-gas emissions. Currently proven steam-based recovery schemes include cyclic-steam-stimulation (CSS), steamflooding, and steam-assisted gravity-drainage (SAGD) processes, which are accompanied by many economic and environmental challenges. Coinjection of solvent with steam is a technology that has the potential to improve the efficiency of steam processes as well as reduce energy usage and carbon dioxide emissions. In recent years, researchers and industry professionals have attempted to develop the process further by conducting fundamental research as well as field pilot trials, with varying degrees of success. However, the current level of understanding of the process and the knowledge surrounding the fundamental physics and mechanisms involved are not entirely satisfactory. In this paper, a parametric simulation study was performed to address the key aspects of the solvent-coinjection (SCI) process that contribute to further understanding and development of the process. Simulation observations were verified with experimental evidence where available to support the results and conclusions. Effects of several operational and geological parameters were evaluated on the performance of the SCI process, and the relative performance benefits were assessed over normal SAGD operations. These parameters included solvent type, solvent concentration, initial-solution gas/oil ratio (GOR), relative permeability curves, and pay thickness. The results revealed that the optimal solvent should not be chosen only on the basis of mobility-improvement capability, but also under consideration of other operational, phase- and flow-behavioral and/or geological conditions that are set or present. Higher concentrations of solvents showed more energy-saving upsides than rate-acceleration benefits. It was also observed that the reservoir steam-intake rate is still likely to be the prime performance indicator of the SCI process. In addition, SCI showed that the potential exists for accessing more resources, particularly below the producer level. Furthermore, steam trap control on the producer seems to be problematic when used for SCI simulation. With the current well-control capacity of simulators, a higher degree of subcool is likely to be needed to avoid live vapor-phase production from the producer.
- North America > Canada > Alberta (0.67)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Firebag Oil Sands Project > Wabiskaw-McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Leismer Oil Sands Project (0.98)