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Abstract A steam chamber generally rises steadily in the channel sands of Athabascaoil sands during a SAGD operation. It is commonly known that steam chambergrowth rate is mainly dependent to permeability. Once the steam chamberreaches the upper boundary, it starts to expand laterally. This is thebasic concept of steam chamber growth of SAGD process in fine sands. However, the growth of steam chamber measured through the analysis oftemperature changes from observation wells behaves different in many instancesthan the commonly accepted steam chamber growth concept, explainedabove. In these observation wells, the steam chamber deviates from theusual behavior; sometimes stops and then resumes rising or shrinking, or evendisappears during SAGD process. This can be caused by the specific natureof steam fingering phenomenon during SAGD operation. Many simulation studies have been conducted to understand the steam risingphenomenon during SAGD operations. At the top of the steam chamber, steamfingers seemed to be created where steam flows through and the steam chamberexpands vertically. If steam fingering actively develops, steam chambergrows steadily as expected. However, activity of fingering can bedisturbed under certain conditions, which can result in various alterations inthe growth of steam chamber. In this paper, the steam fingering phenomenon during SAGD process isdiscussed with actual measured field data from four SAGD projects; UTF Phase A, UTF Phase B, Hangingstone and Surmount. Introduction SAGD performance can be evaluated whether the steam chamber reaches theexpected vertical growth for given reservoir parameters. Generally, whenthe steam chamber rises to the expected height in expected time, SAGD processis determined to be successful. Otherwise, it should be terminated inextreme cases. It is commonly accepted that steam chamber growth rate highly depends onpermeability. Figure 1 illustrates the relationship between the height ofrising steam chamber above the injector and the horizontal permeability fromthe simulation results, and in this case the ratio of horizontal to verticalpermeability was set to 2. Horizontal permeability versus the growth rateof the steam chamber at 15 m above the injector is shown in Figure 2. FromFigures 1 and 2, it is confirmed that steam chamber growth is proportional topermeability. Solution gas effect on the steam chamber growth is includedin Figure 3. Similar steam chamber growth is observed for the cases withand without solution gas. Figure 4 illustrates the height of steam chamberat various operating pressures. As the operating pressure increases thegrowth rate of the steam chamber increases. In the field, rise of the steam chamber, in other words, vertical growth ofthe steam chamber during SAGD process is extremely influenced by thedevelopment of steam fingers at the top of the steam chamber. It isobserved that any type of distraction to the development of the fingering atthe top of steam chamber can sometimes result in the deviation from theexpected behavior of chamber growth, such as shrinking or disappearing; causingunsuccessful SAGD process in extreme cases. In this paper, steam fingering phenomenon at the top of the steam chamberduring SAGD process is discussed for the first time through the review ofnumerical history matches of the real field observation data.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.48)
- Geology > Geological Subdiscipline > Geomechanics (0.47)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Hangingstone Oil Sands Project (0.99)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field A Field > Silurian Tanezzuft Formation > A1 Well (0.99)
- North America > Canada > Alberta > Hangingstone Field > Pc Hangingstone 7-16-84-11 Well (0.97)
Abstract In West Central Saskatchewan the Mississippian/Devonian middle Bakken Formation was deposited as NE-SW trending sand ridges, capable of producing heavy oil. In the Court field, the middle Bakken sand pool has been operated as a heavy oil waterflood for over 15 years with significant success. A review of an earlier field simulation was conducted, an updated model generated, and the potential for reduction in well spacing has been identified. The lateral continuity of the sand ridge is variable due to post-depositional sinkholes. This structural complexity was mapped based on 3D seismic and well-logs and incorporated into the model. There were also stratigraphic disparities to take into account as discontinuous interbedded siltstones are potential flow barriers that create anisotropy in the permeability. Accordingly, grid orientation was modified to align axially with the main sand ridge permeability trends. Reservoir properties were re-assessed through correlation of cores, well-logs, porosity and permeability maps. Improved resolution was obtained with an increase in the amount of grid blocks used to account for the effect of grid orientation and numerical dispersion on the saturation distribution. A thorough analysis of pressure history, production/injection rates, waterflood performance by pattern interference, and dye injection tests were used to control the history matching process. The simulation model was then used to evaluate the downspacing potential and waterflood optimization of the middle Bakken reservoir. Introduction The Court field, located in west central Saskatchewan T33 R27 & R28 W3M, produces 17oAPI heavy crude from the middle Bakken Formation, using vertical wells and a waterflood recovery scheme. Improved understanding of the reservoir behavior is essential to continued field development and successful waterflood management. This paper documents the use of production and seismic data to update and substantiate a simulation model which was used to evaluate downspace potential. Geological Overview The Court field produces hydrocarbons from both the Bakken and Mannville Formations; this paper focuses on the middle Bakken sandstone reservoir. Bakken The Lower Mississippian Bakken Formation in the Court area is interpreted to have been deposited in a marine shelf environment and later reworked into tidally influenced sand ridges(1). Locally, the NE - SW trending sand ridges can reach 18m in thickness and are separated by narrow, tight inter-ridge areas that can be less than 2m thick. Structurally, the area has a relatively gentle SW regional dip. This has been modified post-depositionally by differential Prairie Evaporite salt solutioning and local collapse features of the underlying Torquay Formation's dolomitic limestones, characterized as sinkholes. Pre-Cretaceous erosion has cut down to or through the Bakken and oil was trapped stratigraphically by shale in the preserved Court middle Bakken sand trend. With the exception of local structural lows, the sands were entirely filled with oil. The same ridge trend contains the Court Unit and Court NE (collectively, the main pool) as well as Court SW, which was separated by erosion from the Court main pool. The land map for the area of interest is shown in Figure 1. The ridge appears to narrow and pinch out at the extreme edge of the Court NE pool. The middle Bakken sand is typically fine to very fine grained and composed almost entirely of quartz with minor amounts of feldspar and clay. It is commonly unconsolidated, although the base of the sand can contain a few meters of shaly, cemented, non-reservoir sediments that were probably the pre-cursor to the ridge itself. Minor, discontinuous shale interbeds may interrupt the vertical continuity of the reservoir sand. The arithmetic average intergranular porosity of Court was 29% while the permeability averages 2100 millidarcies. Initial water saturation was approximately 20%.
- North America > United States > North Dakota (1.00)
- North America > Canada > Saskatchewan (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.44)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract A sound geological model, a consistent geocellular model, and flow simulation are all critical components to successful optimization of a heavy oil waterflood project. Despite the availability of a sound geologic model, high quality seismic and abundant core, log, and production data, optimization of the waterflood project at the Smiley Buffalo field in south-central Saskatchewan held many challenges The primary reservoir at Smiley is the middle Bakken sandstone which was deposited as offshore sand ridges in late Devonian to early Mississippian time. The reservoir structure has been subjected to post-depositional solutioning of the underlying Torquay Formation and karstification which causes reservoir breaks, fracture networks, and irregularities in the saturation functions. These features have important effects on reservoir performance. The geologic model and seismic information were used to construct a consistent structural model. A facies classification model was built with fuzzy logic which used the core and log data as well as the geologic model. Sequential indicator simulation was used to populate the structural model with facies information, and sequential Gaussian simulation was used to populate the petrophysical properties. Representative models were selected for upscaling and flow simulation and subsequent well location selection. Introduction A detailed understanding of reservoir behaviour is important for profitable management of mature and declining pools. Geomodelling and flow simulation afford the opportunity to observe reservoir behavior under alternative strategies and help with pool management. The Smiley Buffalo field, located in southern Saskatchewan (Figure 1), is a mature heavy oil reservoir that has complex geologic features that complicate reservoir management. Improved understanding of the Smiley Buffalo field was gained by constructing a geomodel and submitting the model to flow simulation to help to identify areas of missed opportunity. The findings are currently being used for reservoir management decisions. The predominant complicating feature of the reservoir is that it sits above the carbonate Torquay formation which has experienced post depositional erosion and karstification. The fractures generated during this structural deformation provide conduits for out-of-zone water infiltration and compartmentalization of reservoir regions. This paper documents the approach used to characterize the reservoir and predict reservoir behavior. The conceptual geological model is covered first, followed by the geostatistical model and then flow simulation. General Geology The primary reservoir at the Smiley Buffalo oilfield (Figure 2) is the Middle Bakken sandstone which was deposited as an offshore sand ridge in late Devonian to early Mississippian time. It was one of a series of elongate tidal sand ridges trending NE-SW in west-central Saskatchewan (Figure 1). The Late Devonian to Early Mississippian Bakken formation in west-central Saskatchewan is a siliciclastic unit which lies above the Devonian Big Valley Formation and below the Mississippian Madison Group carbonates. The thickness of the suprajacent carbonates is extremely variable due to the incision of the pre-Cretaceous unconformity which has removed variable amounts of the carbonates (Figure 3). The Bakken formation is subdivided into the upper, middle, and lower units throughout Saskatchewan. The lower and upper Bakken are composed of finely-laminated, highly organic rich black shale. They tend to be homogeneous, waxy, fissile to well indurated, non-calcareous to slightly calcareous, pyritiferous, and uraniferous.[1]The shales provided good marker beds as they are consistently present throughout the study area.
- North America > Canada > Saskatchewan (1.00)
- Oceania > Australia > Western Australia > Timor Sea (0.94)
- North America > United States > Texas > Leon County (0.94)
- North America > United States > South Dakota > Harding County (0.94)
- Phanerozoic > Paleozoic > Devonian > Upper Devonian (1.00)
- Phanerozoic > Paleozoic > Carboniferous > Mississippian > Lower Mississippian > Tournaisian (0.64)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.89)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.88)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Wyoming > Wind River Basin > Madison Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (8 more...)
The Role of the Value of Information and Long Horizontal Wells in the Appraisal and Development Studies of a Brazilian Offshore Heavy Oil Reservoir
Branco, Celso Cesar M. (Petrobras S.A.) | Capeleiro Pinto, Antonio Carlos (Petrobras S.A.) | Tinoco, Paulo Marcos Bastos (Petrobras S.A.) | Vieira, Paulo Marcos F. (Petrobras S.A.) | Sayd, Alexandre Dutra (Petrobras S.A.) | Santos, Renato Luiz Almeida (Petrobras) | Prais, Fabio (Petrobras Intl.)
Abstract Recent exploration efforts in the Campos Basin, offshore Brazil, have resulted into important discoveries of what is known as "offshore heavy oil" (API gravities below 18 and reservoir viscosities above 20 cp). Actually, these accumulations have been known since the beginning of the development of the Basin, in the 80s, but they were never given a chance of development due to the technology challenges involved. The maturation of lighter oil fields, associated with recent technology developments (1,2,3), has boosted the interest for these heavy oil resources set aside for many years. This paper describes a case history concerning the strategy for the appraisal of a large offshore shallow carbonate 12 API reservoir, at 100m water depth. To justify the investments in obtaining static and dynamic information of the reservoir behavior, a preliminary development plan based on long horizontal wells was established. The value of the new information (VOI) was estimated through the assessment of the impact that uncertain reservoir and production attributes could have on the development plan. Uncertainty analysis based on reservoir simulation allowed the identification of the main variables affecting the project: reservoir oil viscosity, permeability and effective footage of the horizontal well. This analysis revealed the best strategy for the appraisal of the well planning and led to the approval of a 2000m horizontal well. On a second stage of the study, after the successful drilling and testing of the well, another VOI study was carried out, aiming at the evaluation of the benefits of a one-year extended well test, which is planned to start in 2007. At this stage, the main reservoir uncertainty was the aquifer support, which could relief the need for sea water injection (besides this there are other production uncertainties as flow assurance, performance ofthe pumping system and oil water separation). This paper describes the simulation model building process, the difficult task of assigning scarcely sampled rock and fluid properties, the uncertainty study and the use of quality maps for placing the wells. Simulations results have shown the importance of the well footage and its effectiveness in contacting the reservoir rock. Introduction In the past years Petrobras, the Brazilian National Oil Company, has developed and applied technology (1,3) and field tests to face the enormous challenge of economically producing the reserves of heavy and extra-heavy oil discovered in the Campos Basin, offshore Rio de Janeiro, Brazil. New technologies in reservoir engineering, artificial lift, flow assurance, well technology and primary processing, have been continuously evaluated. In 1980, the carbonate reservoir Xwas discovered, bearing about 300 MM m3 of extra-heavy and viscous oil (12 API, 320 cP in the reservoir), at a 100 m water depth and 900 m TVD. However, given the high oil viscosity and the existence of lighter oil in deeper reservoirs in the same area, the interest in its development was significantly reduced. In 1993, a vertical development well, designed for the deeper reservoir, was tested and a bottomhole oil sample collected. Operational problems during the well test, including water production, made it very difficult to quantify the reservoir parameters. Mainly due to the extra-viscous oil characteristics, reservoir X has since then been considered non-commercial. Recently, with focus on the offshore heavy oil development, new studies were made, which led to the drilling and testing of a pilot vertical well, later side-tracked to a long (2000 m) horizontal section well, revealing a better than expected reservoir scenario.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Overview > Innovation (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
Abstract SAGD (steam-assisted gravity drainage) is a robust thermal process that has revolutionized the economic recovery of heavy oil and bitumen from the immense oil sands deposits in western Canada, which have 1.6 to 2.5 trillion barrels of oil in place. With steam injection, reservoir pressures and temperatures are raised. These elevated pressure and temperatures alter the rock stresses sufficiently to cause shear failure within and beyond the growing steam chamber. The associated increases in porosity, permeability, and water transmissibility accelerate the process. Pressures ahead of the steam chamber are substantially increased, which promote future growth of the steam chamber. A methodology for determining the optimum injection pressure for geomechanical enhancement is presented, which allows operators to custom-tailor steam pressures to their reservoirs. In response, these geomechanical enhancements of porosity, permeability, and mobility alter the growth pattern of the steam chamber. The stresses in the rock will determine the directionality of the steam chamber growth, and these are largely a function of the reservoir depth and tectonic loading. By anticipating the SAGD growth pattern, operators can optimize on the orientation and spacing of their wells. Monitoring of the SAGD process is central to understanding where the process has been successful. Methods of monitoring the steam chamber are presented, including the use of satellite radar interferometry. Monitoring is particularly important to ensure caprock integrity, as it is paramount that SAGD operations be contained within the reservoir. There are several quarter-billion dollar SAGD projects in western Canada that are currently in the design stage. It is essential that these designs use a fuller understanding of the SAGD process in order to optimize on well placement and facilities design. Only by including the interaction of SAGD and geomechanics can we achieve a more complete understanding of the process. Introduction Geomechanics examines the engineering behaviour of rock formations under existing and imposed stress conditions.SAGD imposes elevated pressures and temperatures on the reservoir, which then has a geomechanical response. Typically, the SAGD process is used in unconsolidated sandstone reservoirs with very heavy oil or bitumen. In situ viscosities can exceed 5,000,000 mPaโขs (mPaโขs ? cP) under reservoir conditions. These bituminous unconsolidated sandstones, or "oilsands" are unique engineering materials for two reasons:firstly, the bitumen is essentially a solid under virgin conditions; and secondly, the sands themselves are not loosely packed beach sands. Instead, they have a dense, interlocked structure that developed as a result of deeper burial and elevated temperatures over geological time. In western Canada, the silica pressure dissolution and re-deposition over 120 million years developed numerous concavo-convex grain contacts[1,2,] in response to the additional rock overburden and elevated temperatures. As such, these oilsands are at a density far in excess of that expected under current or previous overburden stresses. Furthermore, once oilsands are disturbed, the grain rotations and dislocations preclude any return to their undisturbed state. Oilsands, by definition, have little to no cementation. As such, their strength is entirely dependent upon grain-to-grain contacts, which are considerable in their undisturbed state. These contacts are maintained by the effective confining stress. Any reduction in the effective confining stress will result in a reduction in strength. Since the SAGD process increases the formation fluid pressure, it reduces the effective stresses and weakens the oilsand. Disturbance. Once the individual sand grains rotate and translate, there is an increase in bulk volume ("dilation") due to an increase in porosity. The associated increase in absolute permeability can be a factor of 10. It is this remarkable behaviour of oilsand that makes geomechanics so important to the SAGD process.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.88)
- North America > United States > Montana > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- 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 > Hangingstone Oil Sands Project (0.99)
- North America > United States > Texas > East Texas Salt Basin > Shell Field (0.93)
Abstract We present two versions of a Darcy-scale model for simulation of the solution gas drive in heavy oils. Presence and behaviour of a foamy-oil effect appears to be critical to the cold production process. This process is not a well-understood production mechanism because a wide range of different petrophysical parameters and experimental factors interact in a rather complex way. Over the past few years, a number of efforts have been made, in many institutions, in order to understand and model the solution gas-drive mechanism in primary heavy oil recovery. Conventional simulations succeed in matching actual field productions but are not reliable for prediction forecast purposes (large uncertainties on recovery factors). We present an evolving nucleation and flow model for solution gas drive in heavy oil. The model is built at the Darcy scale and involves the effect of capillarity on bubble flow and phase change. An ad hoc simulation tool is built to analyze carefully the properties of the model. The tool allows to reproduce laboratory experiment across a sample rock. In the limit of infinitely slow depletion, an asymptotic theory is constructed that allows to predict analytically the pressure difference across a sample. The theory predicts a pressure gradient at first order without additional calculation, and the gradient appears, at first order, independent on the gas formation (degassing) kinetics. No saturation gradient is predicted at first order. The results are compared to numerical simulations and experiment, and good agreement is found in cases where the pressure gradient is known. In a second version of our model we introduce the effect of capillarity on bubble growth. Capillarity delays bubble growth by stabilizing small bubbles under a certain critical radius. This new term leads to nucleation fronts propagating rapidly through the sample. It appears more difficult to predict a saturation gradient. The causes of this difficulty are analyzed. INTRODUCTION Many efforts have been made recently to understand and model the solution gas drive mechanism in primary heavy oil recovery. Present day models are unreliable, as even though conventional simulations can succeed in matching field productions, they fail to capture the actual physics of the solution gas drive process in heavy and extra-heavy oils. A "foamy-oil" effect related to the bubbly aspect of recovered oil, enhanced oil recovery and higher critical gas saturation has been identified by some authors5,9 but its physical nature is not quite elucidated. In order to better understand the physics of solution gas drive, several experiments have been conducted at the laboratory scale. In this work we attempt to simulate the experiments reported by Bayon et al.[1,2]. The flow rate is imposed so that the pressure decreases in an approximately linear fashion over the duration of the experiment. These experiments were performed under X-ray scan to record the saturation profiles all along the core during the depressurization. It was attempted to model the results of the experiment using both classical Darcy scale models such as those of the Starsยฎ and Eclipseยฎ simulators, and a modified model. Two main difficulties aroseRelative permeabilities have to be adjusted as a function of the rate of decrease of the pressure or depletion rate. In other words, relative permeabilities matched for one depletion rate do not match the results for the other depletion rate. This is a classical difficulty in heavy oil modeling. Measured saturation profiles differ from simulated ones. The measured profiles have marked spatial variations or gradients (this was observed by Egermann et al.[7], Sahni et al.[10], as well as by Bayon et al.[1,2] whose data are reproduced here on Figure 1). On the other hand the simulated profiles are flat. This effect has been confirmed with other models and codes[8]
Abstract In order to study the fluid flow mechanism for cold heavy oil production with sand (CHOPS) and predict their production performance precisely, criteria for the skeleton sand erosion and movable sand startup have been set up, based on the stress analysis on formation rock and sand particulates. According to the principles of effective stress, mass conservation, virtual displacement, equivalent virtual work and so on, both the single-well-black-oil model of CHOPS with three dimensions and four phases and the equilibrium equation of borehole wall rock with elasto-plastic deformation have been established. Considering the basic definitions of physical property parameters and the effect on physical property parameters caused by bulk strain, skeleton sand erosion, movable sand deposition on the pore surfaces and movable sand bridge plug at pore throats, dynamic models of physical property parameters have been established for numerical simulation of CHOPS. Then, the coupling solutions of the model have been studied. Finally, a case to verify the correctness and validity of the model is simulated and analyzed. The establishment of the mathematic model describing the fluid flow mechanism of CHOPS is of great significance to help us recognize correctly and exploit heavy oil reservoirs efficiently. Introduction Globally, heavy oil may account for 50% of the hydrocarbon volume in storage [1]. It is very important that petroleum engineers develop the heavy oil reservoir economically and efficiently. Thermal recovery technology, an efficient heavy oil recovery technology, has been used widely. But its cost is higher than water flooding's. CHOPS at the lower cost has been applied in the exploitation of heavy oil reservoir very well. The establishment of the mathematic model describing the fluid flow mechanism of CHOPS is of great significance to help us recognize correctly and exploit heavy oil reservoirs efficiently. Cold heavy oil production with sand is a process of fluid-solid coupling. Not only fluid particles can flow in the porous media, but also loading will deform reservoir rock and rock particles will be displaced. When the deformation of the rock in the reservoir exceeds the limit, the skeleton of the rock will be damaged and the sands of skeleton will be produced. Parts of skeleton sands, which will enter fluid and move with fluid flow, are called movable sands. They will migrate, deposit or plug the pore throats with fluid flow. In return, they will affect the flow of fluid and the deformation of rock skeleton in the reservoir. In order to improve the production in the CHOPS, the method, increasing draw down pressure to stimulate sand production, is used to enlarge the access of oil flow and decrease the resistance of fluid flow. Because the output of skeleton sands hasn't been taken into consideration in the normal principle research of fluid flow in the formation of deformation media, its mathematic model of fluid flow cannot correctly describe the actual flow status of fluid in the formation with sand production. So, fluid flow mechanism of CHOPS must be studied.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (1.00)
Numerical Modelling Of Advanced In Situ Recovery Processes In Complex Heavy Oil & Bitumen Reservoirs
Card, Colin Charles (Phoenix Consultants) | Close, Jason Christopher (Computer Modelling Group Inc) | Collins, David Albert (Computer Modelling Group Inc) | Sammon, Peter H. (Computer Modelling Group Ltd.) | Wheeler, Thomas James (ConocoPhillips Co) | Fortson, Noble G. (IBM Corp.)
Abstract As development activities in heavy oil and in situ bitumen deposits have accelerated, the challenge of forecasting the performance of in situ recovery processes at field scale has increased exponentially. Delineation drilling results make it apparent that these deposits are highly complex and three-dimensionally heterogeneous.Heterogeneity has a significant impact on the effectiveness and economics of the recovery process. Many experienced operators are recognizing that in addition to the static complexity of the reservoirs it is necessary to consider the dynamic stress state in the regions undergoing production.Geomechanical factors are significant and must be built into any realistic numerical simulation of recovery processes. It has become apparent to operators that modeling single well-pair operations may be misleading, and seven to ten well-pair models are now quite common. All these factors result in increasing size and complexity of numerical simulation models. Reservoir simulator developers have responded with two technologies to achieve reasonable run times in these large and complex models.The combined use of 64-bit symmetrical multiprocessor computers and dynamic grid refinement will be discussed and compared against traditional simulation methods. This paper will provide examples of the application of these leading edge technologies for in situ oil sands development in the Surmont area of the Athabasca deposit. Introduction The investigation discussed in this paper began with a 3D "STATIC FINE" (or SF) simulation model of a typical 9-wellpair ยฝ-pad, gridded in the I, J, K (vertical) directions with 45x1x1m grid cells.This is the base simulation model.It was statically gridded to accurately model the thermal and flow regimes that occur perpendicular to the well paths, i.e. in the cross-sectional plane.Such a model requires 64-bit address space with memory requirements of approximately 16 GB of RAM.The forecast results and performance of this finely gridded model formed a base for comparison with the results obtained from all other models. This model was coarsened in the J direction to 45m so that the resulting model would fit within the 32-bit environment of desktop PC's, i.e. memory requirements for the model cannot exceed 3 GB of RAM.This model was designated the "COARSE" grid model. The results of a forecast of reservoir performance with this model were compared to those obtained from the SF model. Large models such as the SF model take a long time to run in serial or single-processor mode.We therefore extended the investigation with this model to cover the use of parallel processing, using up to 8 CPU's in a shared memory, symmetric multiprocessor (SMP) environment.This approach also took advantage of IBM's simultaneous multithreading (SMT) technology. Static gridding of these models is wasteful of resources and time.The fine grid is only required in areas of the model where there are substantial changes in variables - temperature, saturation, viscosity, flow rate, and pressure for example - over relatively short distances (< 5 meters). To address this, the technique of dynamic gridding was applied to the SF model and this DYNAMIC FINE gridded model (or DF model) was run in serial (single processor) mode using a 64-bit machine.The run time for this model was compared with that for the SF model, for equivalent forecast results. Finally the DF model was run in parallel mode for additional speed up and comparable simulation results. The above models attempt to model the effects of stress on reservoir properties such as porosity and permeability using pressure dependent porosity in conjunction with static permeability multipliers.To address these effects further, a 2 well-pair finely gridded element of symmetry model was set up as a base case and four different approaches to modeling the effect of stress on porosity and permeability were investigated.
- North America > Canada > Alberta (0.46)
- North America > United States > Texas (0.28)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Hardware (1.00)
- Information Technology > Architecture > Distributed Systems (0.34)
Reservoir Characterization of the Wabiskaw B in the Kirby Area, Alberta, Canada
Mathison, J. Edward (Fekete Associates Inc.) | Mireault, Raymond A. (Fekete Associates Inc.) | Wilhelm, Jason K. (Fekete Associates Inc.) | Alwast, Norbert (Fekete Associates Inc.) | Williams, Sarah (Fekete Associates Inc.)
Summary An integrated geological and engineering framework of the Kirby Wabiskaw B reservoir has permitted a retrospective analysis of two steam flood pilots that failed to achieve commercial success. The analysis identified four factors that negatively impacted the pilots and which would need to be addressed prior to future steam floods. The factors are: Laterally extensive calcite cemented horizons, interbedded mudstones, pore plugging kaolinite and clay diagenesis upon contact with steam. Introduction Beginning in the late 1990's, and continuing to 2005, significant debate has raged in Alberta on the advisability of permitting the depletion of gas overlying immobile bitumen. Unlike conventional oil recovery, depletion of a gas cap does not directly affect reservoir drive for bitumen. In a steam flood, the overlying gas creates a pressure blanket that prevents steam escaping from the bitumen zone. Owners of the bitumen rights assert that the bitumen represents the greater asset to the Province of Alberta and that gas production should not be permitted until such time as the bitumen is recovered. In general, it has been accepted that a minimum of 10 metres of bitumen pay is required for thermal recovery. The authors were commissioned to conduct a widespread and detailed examination of the bitumen deposits in the Kirby area to map regions of exploitable bitumen and, by extension, where the gas may be produced in those regions of thin, non-exploitable bitumen. Over 1000 well were evaluated in the study with bitumen, gas, and water thicknesses mapped and hydrocarbon saturations determined. Cores from over 40 wells where described in detail with 16 thin sections collected from 4 of these wells. Scanning electron microscope (SEM) and X-ray diffraction (XRD) were performed on 7 samples to determine clay types and distribution within the reservoir. Isotopic analysis was undertaken on 5 samples of calcite cements to determine stable isotope (carbon and oxygen) composition. Our work compliments the more extensive petrographic, SEM and XRD work of Dekker et al1, Beckie and McIntosh2, and Shier3. Our stable isotope investigation of calcite cements augments the work of Shier3. Analysis of permeability and bitumen saturation of cored wells within Townships 73โ74 Range 8W4M and from two steam pilots in section 29โ73โ7W4M and section 1โ73โ6W4M was also undertaken. These analyses were compared with bitumen saturations and permeabilities from core in the Hilda Lake Clearwater SAGD pilot (Township 64 Range 3W4M). Engineering appraisal was undertaken on the two pilot sites (IHOP and PHOP Fig. 1) in the Wabiskaw B Formation and at the Cold Lake and Hilda Lake sites in the Clearwater Formation (Townships 64โ65 Range 3 W4M). The result was a refined geological framework which permitted a retrospective understanding of the two Wabiskaw B steam flood pilots that, while each having in excess of 20 metres of bitumen pay, failed to achieve commercially viable production rates. This paper examines the geological and engineering evidence on macro, meso, micro and molecular levels, each of which contributes to the explanation of the performance of the pilots. The Wabiskaw B reservoir, within the Kirby area of Alberta (Townships 71โ75 Ranges 3โ10), occurs between the Cold Lake thermal recovery projects to the south and the Athabasca bitumen mining projects to the north (Fig. 1)The Wabiskaw B is a significant bitumen resource with total pay of over 30 metres in the thickest part of the reservoir. Viscosity of the bitumen varies from 30,000 to 82,300 mPa necessitating thermal recovery techniques. Upon first examination, the log characteristics appear comparable to the successfully steam flooded Cold Lake Clearwater reservoir in Townships 64 - 65, Range 3W4M (Fig. 2).
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Wabiskaw Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract The increasing complexity in the development of heavy oil fields is directly associated with the uncertainties in the fluid and reservoir characterization, particularly, in offshore scenarios where difficulties for well testing and fluid and core sampling are present. A probabilistic analysis, instead of a deterministic one is the natural way to face these expected uncertainties. The approach proposed in this work uses experimental design techniques to determine the parameters that have large contribution into the Net Present Value (NPV) of the prospect being analyzed. In the example presented NPV is estimated based on the accumulated oil production response of a flow simulator over a period of 30 years. An uncertainty analysis was done using information about the probabilities of the uncertain parameters. The decision tree technique was used to map all possible outcomes and then to estimate the Expected Monetary Value. A program was written to manage the input/output files of a commercial black-oil reservoir simulator in order to run a total of 1,728 simulations and estimate the NPV for each one of those parameter combinations. In a second analysis, the uncertainty density distribution was derived based on the histogram of the NPV results, assuming that the values of the uncertain parameters cover the entire range of variability. This procedure was applied to a synthetic case in which the uncertain parameters selected were: porosity, absolute and relative permeability, area of accumulation and exploitation scheme (horizontal or vertical wells). Introduction The rising difficulty to find conventional reservoirs i.e. trapped in uniform structures, containing light oil, with high permeability, high pay zones and easy access, where the uncertainties to its development and associated risk are not too high, leads to increasing efforts to turn marginal prospects in economical ones. Current high oil prices as well as technological advancements are also boosting these projects, in which the increasing complexity in its development is directly proportional to the increasing of its uncertainties. In the particular case of offshore heavy oil scenarios, the difficulty to recover representative fluid samples, due to the high fluid viscosities, conducts to unreliable information of the PVT properties. In addition, the highly unconsolidated formations, which are commonly associated with heavy oil, increase the difficulty to obtain representative core samples, leading to non-consistent measurements of petrophysical properties like absolute and relative permeability, fluid saturations and porosity. Also, the high oil viscosities together with the high sand content make the well testing operations more complicated and consequently poor well potential information is obtained. In such cases, where the decisions about the entire field development process have to be taken under strong conditions of uncertainty, a probabilistic analysis, instead of a deterministic one, is the natural way to proceed. Based on that, this work aims to present an application example of the Experimental Design and Risk Analysis techniques to asses the uncertainty of the Net Present Value in a synthetic offshore heavy oil reservoir during its initial development stage. The reservoir, located under a water depth of 1,500 m. and approximately 1,500 m. below the sea bed, requires, as any development in these conditions, a great amount of investment and therefore it is crucial to recognize and analyze each possible outcome for the field development in order to map the uncertainties and the resulting financial outcomes. This work was oriented to assess uncertainty of the Net Present Value under different possible values of variables related to the reservoir characterization and production process during the earliest stage of the field development. For this reason, only constant values of porosity and permeability through the entire reservoir were considered and not a distribution of them, as it should be done when a more detailed study is conducted.