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Abstract Horizontal injection wells could be widely used in geological storage projects to provide large injectivities into formations with less favorable permeability-thickness products. Injection induced fracturing, which plays an important role in injection and storage risk assessment, is much more complex for horizontal well than vertical well,. The temperature variation of formation around wellbore due to cool CO2 injection introduces thermo-elastic stress which dramatically decrease critical fracture pressure under some strategies. According to the definition of thermo-elastic stress, the temperature profile of CO2 in horizontal wellbore essentially determines its magnitude. A model is developed to describe heat transfer between wellbore fluid and surrounding formations by extending our previous heat transfer model of vertical wellbore. In the model, CO2 flux along horizontal wellbore is divided to uniform and non-uniform flux. Mass flow rate of the former case is linear; in the latter case, mass flow rate depends is non-linear and depends of the pressure drop along the wellbore, which is related to friction loss. The model analyzes factors that affect temperature difference between wellbore CO2 and formation by several dimensionless groups: (1) dimensionless ratio of the rate of heat transfer to the rate of advective transport of enthalpy in vertical wellbore; (2) the length ratio of horizontal well over vertical well; (3) dimensionless friction factor. With new criterion by considering the influence of thermo-elastic stress, we optimize perforation zone of horizontal wellbore to prevent fracturing. Additionally, the influence of formation properties wellbore pressure is discussed to estimate safe perforation zone of horizontal wellbore.
- North America > United States > Oklahoma > Anadarko Basin > M Formation (0.99)
- 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)
- (3 more...)
Abstract Bitumen production from the Athabasca Oil Sands in northeast Alberta, Canada typically uses steam-assisted gravity drainage (SAGD) techniques. For shallow bitumen resources, low pressure, SAGD (LP-SAGD) and expanding solvent, LP-SAGD (SLP-SAGD) techniques are viable options for such developments as these methods maximize bitumen production and control steam-oil ratios (SORs), while maintaining asset integrity throughout the life of the project. In Alberta, applications requesting approval for pilot-scale, thermal exploitation of bitumen resources are submitted to the Energy Resources Conservation Board for review. As part of the application process, thermal reservoir simulation studies are often conducted, forecasting 10 years of asset development using SAGD. The authors recently completed a 3D, pseudo-component, thermal, reservoir simulation study of the proposed Clearwater West, Phase 1 Pilot Project located southeast of Fort McMurray, Alberta. The simulation program, STARSโข, was used for this investigation. Three potential development strategies for the Pilot Project were evaluated. These strategies included LP-SAGD, where 100% coldwater equivalent (CWE) steam is continuously injected into the reservoir for 10 years. The other cases were SLP-SAGD, where the injection stream consists of 75% CWE steam and 25% solvent is continuously injected into the reservoir for either 10 years or for 7 years, followed by wellpair blowdown and the termination of solvent injection. Comparisons of key modelling parameter results, such as steam chamber development, bitumen production and recovery, SORs and solvent loss, were completed for all development strategies. A sensitivity study was also conducted.
- North America > Canada > Alberta > Athabasca Oil Sands (0.25)
- North America > Canada > Alberta > Census Division No. 16 > Regional Municipality of Wood Buffalo > Fort McMurray (0.24)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract Porosity is a key reservoir parameter and high accuracy is needed to properly estimate reserves. But even though there is a long history of porosity measurements and various tools from which to derive it, this can still remain a difficult task. None of the logging tools directly measure porosity but instead respond to density, lithology and fluid. Combining different measurements can help to solve for porosity but also brings the complexity of invasion as all the tools do not have the same radial response. This problem is even more complex when dealing with gas formations as the fluid effect on the measurements is very high. This paper looks at various methods to improve porosity computations via the integration of Nuclear Magnetic Resonance (NMR) and other porosity measurements in South China Sea gas reservoirs.
- North America > Canada (0.28)
- Asia > China (0.25)
Abstract Analytical models to predict the performance of thermal recovery processes are useful tools for preliminary forecasting purposes and sensitivity studies and provide a better insight than simulation models into the physics of thermal processes. Classical models such as Marx and Lagerheim (1959), Willman (1961) and Farouq Ali (1971) are used extensively for steam-flood performance prediction. Several studies have been conducted to develop the theory for the estimation of the radius of the heated zone. This radius is important for computing the volume of recoverable oil, as well as to determine well spacing in steamflooding and cyclic steam stimulation. This work presents an analytical model to estimate the radius of heated zone in either conductive or conductive-convective heat transfer mechanisms, which mainly occur in Steam-Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) respectively. The heat flow equation was combined with mass and momentum convective transport equations in a porous medium, in an effort to correlate the temperature front velocity to the steam advancing front velocity. As the saturation front velocity is known from classical Buckley-Leverett transport equation, at each instant we investigated the transport distance of the heat front in a radial homogenous reservoir. The theoretical model takes gravity into account, but neglects the capillarity, and there is no longer the assumption of piston-like steam drive. CMG-STARS thermal simulation and COMSOL Multiphysics are used to compare and verify analytical model results. The improved model is superior to previous models used to calculate the radius of heated zone and the analytical results are in good agreement with the simulation results.
Abstract Horizontal wells with hydraulic fracture treatments have been proven to be an effective method for developing unconventional oil and gas reservoirs. During the last several years, fracturing methods have evolved and improved rapidly, however, there still exists many uncertainties in fracture design. Several fracture diagnostic techniques have been developed to improve the understanding of the fracturing process. In this study, after reviewing the application and limitations of the current fracture diagnostic techniques, we describe the application of distributed temperature sensing technology (DTS) as a complementary tool for real-time fracture diagnostics. DTS has enabled us to observe the dynamic temperature profile along the wellbore during the treatment. However, quantitative interpretation of dynamic temperature data is very challenging and requires in-depth mathematical modeling of heat and mass transfer during the treatment. We have developed a thermal model to simulate the temperature behavior along the wellbore during the treatment as well as during the shut-in period. This model takes into account the effect of all significant thermal processes involved, including conduction and convection. Examples are presented to illustrate how this model can be applied for fracture stimulation diagnostics. Estimation of the fracture initiation points, number of created fractures, distribution of stimulation fluid along each isolated zone, effectiveness of isolation are the problems that DTS can help us to obtain the answers. This information can be used for more accurate fracture modeling and better estimation of fracture conductivity and fracture geometry, and therefore to optimize the future treatments and also evaluate the well performance.
- North America > United States > Texas (1.00)
- Europe (0.93)
- North America > Canada (0.69)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Information Technology > Communications > Networks > Sensor Networks (0.89)
- Information Technology > Artificial Intelligence (0.69)
Abstract Air-injection-based recovery processes are receiving increased interest due to 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 prior to committing resources, which can be achieved with the use of numerical reservoir simulation. In a previous paper (JCPT, April 2009, pp. 23โ34) it was proposed that, after successful laboratory testing, analytical calculations and semi-quantitative 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 explicitly addressed. This paper discusses a detailed workflow which could 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 which could be either developed specifically for the reservoir in question or taken from public literature. Second, the oil would be characterized in terms of the same pseudo-components employed by the kinetic model and relevant 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. prior to 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 go 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)
- Asia (0.93)
- North America > Canada > Alberta (0.46)
- 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...)
Abstract Numerical simulation of the insitu combustion process is complicated by sharp gradients, with different temporal and special regimes applying to the reaction front and diffusional transport. It is not possible to achieve fine scale solutions at field scale in a reasonable time, owing to the onerous computer requirements. Instead, grid coarsening procedures were used. Simulation solutions were obtained for a homogeneous reservoir section of the THAIยฎ field pilot, near Conklin, Alberta, Canada. The reservoir model did not include an interbedded shale layer, or bottom water layer, and the study therefore represents a non-optimal, first stage simulation of the THAI process, prior to incorporating more reservoir complexities. The results show that the process is inherently stable over a six year operating period, since there was no oxygen in the produced gas. High temperatures are generated in the narrow combustion front zone (900 ยฐC) but 60 m ahead the temperature is 500 โ 600 ยฐC. Rapid desaturation of reservoir water takes place ahead of the combustion front, allowing combustion gases to enter into the colder bitumen layers, thereby creating some oil mobility. Of particular significance, is the existence of a narrow, high saturation, Steam Zone, extending to more than 15 m, and up to 30 m during later stages of production. The steam zone propagates at up three times faster than that of the combustion front. Also, the Mobile Oil Zone (MOZ) is very significant characteristic of the THAI process throughout the whole production period. However, the temperature in the MOZ, close to the horizontal producer well, is quite low, around 150โ180 ยฐC. The oil recovery factor was approximately 60 % in the zone swept by the gas-steam front. Oil production peaked at 69 m/day rate, averaging 350 barrrels per day for the single well pair.
- North America > Canada > Alberta (0.89)
- Europe > United Kingdom > North Sea > Central North Sea (0.25)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
Abstract Geological storage of CO2 in underground formations has the potential to be a major component of any viable solution to reduce atmospheric emissions of greenhouse gases. There are different options for long-term storage of CO2 in subsurface formations currently being considered by both government and industry. In general, the potential sinks for geological storage of CO2 include storage in depleted oil and gas reservoirs, deep saline aquifers, coal beds and salt caverns as well as injection for enhanced oil recovery (EOR). Suitable geological conditions as well as availability of CO2 sources provide a vast potential for geological storage of CO2 in Saskatchewan, Canada. This paper examines and summarizes the potential sinks for geological storage of CO2 in Saskatchewan. More specifically, the potential for CO2 storage in locations throughout Saskatchewan along with estimated storage capacities are discussed in detail. The possible sinks in each storage category have been identified through creation of a database of the available information, screening the sinks according to the appropriate criteria for each category, and evaluating their potential in terms of CO2 storage capacity. The database includes a significant number of oil pools in different stages of development, saline aquifers, and coal beds throughout Saskatchewan. Southeastern Saskatchewan contains deep saline aquifers in addition to several light and medium oil pools which offer a great potential for CO2 EOR and storage. Extensive unmined coal beds also exist in the southern and western parts of the province which can be possible candidates for coal bed methane production and CO2 sequestration. The identification and analysis of the potential sinks for geological storage of CO2 in Saskatchewan will contribute towards the development of integrated CCS infrastructure. This will also help to meet climate change mitigation objectives by reducing CO2 emissions through developing practical applications for geological storage of CO2.
- Phanerozoic > Paleozoic (0.68)
- Phanerozoic > Mesozoic > Cretaceous (0.30)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > Canada > Manitoba > Williston Basin (0.99)
- North America > Canada > Alberta > Williston Basin (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.97)
- (5 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > CO2 capture and management (1.00)
Abstract Simulation of underground coal gasification (UCG) is an integrated approach involving a Thermo-Hydro-Chemical-Mechanical process (THCM). The key is to understand the surface subsidence in the UCG process associated with the cavity growth and roof rock collapse during the coal seam combustion. However, the interaction between the mass transports and thermal-mechanical induced cavity and spalling cannot be fully captured by a conventional flow simulator without coupling geomechanics. The literature has documented numerous methods of modeling the coupled Thermal-Chemical-Geomechanical process for UCG. The objective of this paper is to summarize the current research status and future developments of coupled geomechanical modeling approach for the UCG process, followed by a case study. Geochemistry and chemical reactions are modeled in the thermal reservoir simulator with a well-defined Controlled Retraction Injection Point (CRIP) configuration. A modular coupling approach is utilized in which geomechanical module calculates the changing of the stress and strain due to the changing of pressure and temperature, updating the porosity and permeability simultaneously. Finally, surface subsidence is investigated and limitations are also identified for future development.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.90)
Abstract Several offshore gas fields are present in Adriatic Sea (Italy), producing since the 60s. The gas is produced from multilayer metric sand reservoirs. The declining production in these mature fields is normally offset by drilling new deviated wells. Recent technology evolution shifted the focus from metric reservoirs to thinly laminated intervals (thin beds), until now not produced due to difficulties in indentifying gas bearing zones. This paper proposes a critical review of existing thin beds evaluation techniques and shows a successful case history using wireline formation testing technology. While gas identification in metric reservoirs can be achieved with standard petrophysical measurements, thin beds are challenging since lamination thickness is half inch or less. Even the most advanced petrophysical logging tools struggle in providing discrimination of gas from water in this environment. Conventional pressure gradient approach also does not work, since thin beds often overpressurized and pressures are supercharged due to low mobility. A new wireline formation testing approach for thin beds to discriminate gas from water zones was proposed, using a dual packer string with downhole fluid analysis capabilities, including fluid density measurement. Twelve stations in thin beds were attempted, all resulted representative in terms of fluid identification and pressure measurement. Productivity forecast of the tested intervals was also provided using as input pressures and permeabilities derived from dual packer tests. The possibility to verify gas presence in zones with high uncertainties saved the cost of multiple well testings, optimized the completion strategy of the different reservoirs and allowed to increase the field production and reserves. Several gas fields today producing from metric reservoirs will be revisited in the very near future in order to start production from thin beds, until now untouched. The wireline dual packer approach described in this paper, along with enhancement of petrophysical logs applications, will certainly play a key role in optimal exploitation of thin beds gas reserves.
- Europe > Italy > Adriatic Sea (0.30)
- North America > United States > Texas > Archer County (0.15)
- Europe > United Kingdom > North Sea > Central North Sea (0.15)
- Europe > Italy > Po Basin (0.99)
- Europe > Italy > Adriatic Sea > Adriatic Basin > Barbara Field (0.99)