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Collaborating Authors
Improved and Enhanced Recovery
Abstract High-temperature production well design and equipment installation, particularly for deep petroleum reservoirs, geothermal wells, and steam injection applications, present a multitude of challenges for operators due to the elevated thermal environments that impart high temperatures to the produced fluid (e.g., steam, oil, gas, etc.). One of the foremost problems is the uncontrolled heat transfer to outer annuli and heat loss from the production tubing. This can be detrimental to the integrity of outer annuli, may reduce the well productivity and could contribute to the formation of gas hydrates. In order to efficiently produce, inject or flow these fluids through production conduits to other facilities, it is necessary to keep them thermally isolated to prevent severe reductions in flow rate and dramatic changes in pressure that lead to tubular failure. To avoid these problems, high-viscosity insulating packer fluids (IPFs) are employed to insulate production tubing from the exterior pipe and to provide the required hydrostatic force. Effective fluids have a low thermal conductivity and also remain viscosified to eliminate convective heat transfer. Until recently, the packer fluid options fell short of meeting these objectives at elevated temperatures [i.e., = 250ยฐF (121 oC)] for extended durations. Through the extensive investigation of multidisciplinary technologies, a superior-performing solids-free aqueous-based IPF was developed for applications in deep high-temperature environments. The novel system covers a broad density range and exhibits heat transfer between 0.12 - 0.16 BTU/hr ftยฐF. Ultra high-temperature static aging tests have shown superior gel integrity with no thermal thinning after exposure to temperatures in excess of 500ยฐF (260 oC). The utilization of nanotechnology and a system of intermolecular associating synthetic macromolecules allow for the formation of the superior gel structure. In addition to the ultra-high thermal stability, the fluids possess thixotropic flow properties, are hydrate inhibitive and are environmentally friendly by Gulf of Mexico (GOM) standards. This paper presents and discusses the laboratory data generated under simulated high-temperature well conditions. Introduction One of the major problems in steam injection and geothermal production well design and equipment installation is the uncontrolled heat transfer from the production/injection tubing to the annular space and wellbore casing. The heat transfer from the production/injection tubing during such thermal events can be detrimental to the integrity of the casing as well as to the quality of the steam that is injected into the desired reservoir.1โ3 From a production standpoint, lowering the temperature of the produced or injected fluid (i.e., heavy oil or steam) and the production tubing can reduce the overall well productivity and efficiency.4 Paraffin and asphaltene deposition from the cooled crude oil inside the tubing will restrict the well flow. To avoid these problems, numerous steps have been taken by operators to combat heat transfer by all means.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
Utilizing Natural Gas Huff and Puff to Enhance Production in Heavy Oil Reservoir
Wenlong, Guan (PetroChina Co. Ltd.) | Shuhong, Wu (PetroChina Co. Ltd.) | Jian, Zhao (Tuha Oil Field, PetroChina Company Limited) | Xialin, Zhang (PetroChina Co. Ltd.) | Jinzhong, Liang (University of Petroleum) | Xiao, Ma (University of Petroleum)
Abstract L Block is a super-deep heavy oil reservoir with the degassed oil viscosity of 9,680~12,000mPa.s @50, 2800~3300 m deep with normal pressure system and 80~95 in the reservoir. The GOR is 12m3/m3 and the initial bubble point pressure is only 4MPa. High oil viscosity and low flowability result in low production and rapid decline of primary development. This paper will review mechanisms, feasibility and pilot test of utilizing natural gas huff and puff to enhance production in L Block. Firstly, the paper will detail the lab experiments which include the conventional PVT and unconventional PVT. The conventional PVT shows that the natural gas dissolved in the oil can greatly decrease oil viscosity by 1~2 orders of magnitude and enhance the flowability in one hand, in other hand, it can large the volume coefficient and add the elastic energy. The unconventional PVT shows that the heavy oil can effectively entrap the gas for more than several hours because of its high viscosity. There exists a pseudo bubble point pressure far lower than bubble point pressure in the manmade foamy oil, which is relative to the depressurization rate. Under the condition, the elastic energy could be maintained in a wider pressure scope than natural depletion without gas injection. Secondly, the paper will introduce a special experiment apparatus which can simulate the process of gas huff and puff in the reservoir. The huff and puff experiment shows that in this process the foamy oil can be seen and most of oil flows to the producer in pseudo single phase, which is one of the most important mechanisms of enhancing production. Finally, the paper will brief the pilot test of single well, which shows that the oil production is increased to 5~6 m3/d from 1~2m3/d by natural gas huff and puff and the stable production period is prolonged to 91days in the first cycle and 245 days in the second cycle from 5~10 days before huff and puff. Introduction L Block is a super deep heavy oil reservoir located in the North structural belt of Tuha Basin, western China, with the degassed oil viscosity of 9,680~12,000mPa.s @50, 2800~3300 m deep with normal pressure system and 80~95 in the reservoir. The GOR is 12m3/m3 and the initial bubble point pressure is only 4MPa. High oil viscosity and low flowability result in low production and rapid decline of primary development. At present, steam injection is the most popular method in China for heavy oil production. But steam injection is not suitable for L Block because its deepness results in low thermal efficiency. Heavy oil reservoirs with foamy oil behaviors in the Venezuelan Orinoco Belt and in Canada 1~7 behaved good production performance. But L Block presents hardly foamy oil behaviors because of its low GOR and low initial bubble point pressure. In this condition, natural gas injection under high pressure is another considerable method for heavy oil production by means of imitation foamy oil, which especially fit in with development of supper deep reservoir. This paper will review mechanisms, feasibility and pilot test of utilizing natural gas huff and puff to enhance production in L Block. Firstly, the paper will detail the lab experiments which include the conventional PVT and unconventional PVT. Secondly, the paper will introduce a special experiment apparatus which can simulate the process of gas huff and puff in the reservoir. The huff and puff experiment shows that during this process the foamy oil can be seen and most of oil flows to the producer in pseudo single phase, which is one of the most important mechanisms of enhancing production. Finally, the paper will brief the pilot test of single well, which shows that the oil production is increased to 5~6 m3/d from 1~2m3/d by natural gas huff and puff and the stable production period is prolonged to 91days in the first cycle, and 245 days in the second cycle from 5~10 days before huff and puff.
- Asia > China (1.00)
- North America > United States > Texas (0.28)
- South America > Venezuela > Orinoco Oil Belt (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)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract A statistical study of 166 western Canadian waterfloods recovering heavy and medium gravity oils revealed new findings about best operating practices for heavy oil waterflooding. In classical light oil waterflooding, operators are advised to start waterflooding early and maintain the voidage replacement ratio (VRR) at 1. The study, however, produced surprising results for 2 parameters - among the 120 reservoir and operating parameters investigated - that ran counter to the recommended practices of classical light waterflooding. Delaying the start of waterflooding until a certain fraction of the original oil in place was recovered was found to be beneficial. Secondly, varying the VRR was shown to correlate with increased ultimate recovery - periods of under injection are needed, although a cumulative VRR of 1 should be maintained. Ultimate recovery was correlated with the primary recovery factor at the start of the waterflood. No trends appeared when the full set of 166 waterfloods was inspected. However, when the dataset is analyzed by ranges of API, a "sweet spot" of improved ultimate recovery was observed in a very narrow window of oil recovery factor prior to the start of waterflooding. Graphs of each category showed this "sweet spot" window where improved recovery occurred. These categories were API ranges; as well as ranges of permeability*height/viscosity (kh/ยต); and pattern development. Also increases in ultimate recovery were observable when we examined graphs of ultimate recovery versus the fraction of injection volume that was underinjected - but again, only when the data was analyzed by the ranges. A certain period of injection when the VRR was less than 0.95 resulted in increased ultimate recoveries. However, it is important that this period of VRR < 0.95 be offset with periods of increased VRR so that the cumulative VRR cycles around 1.0. Again, each range manifested a narrow "sweet spot" for where this increase in ultimate recovery occurred. Introduction Waterflooding is becoming increasingly important in recovering heavy oil. In western Canada, 5201 million m3 of heavy oil is in place in Alberta and Saskatchewan, and more than 200 waterflood operations recover over 24% of that oil in place. Those western Canadian oil pools represent the largest source of data regarding recovery of oil as heavy as that found in many Alaskan oil pools. In order to optimize waterflooding strategy for the Alaskan oil pools, we examined the results of up to 50 years of waterflooding on 166 western Canadian waterfloods recovering oil of less than 30ยฐAPI. Practices for waterflooding of conventional light oils were initially researched in the 1940's by Buckley and Leverett 1 and little has changed since Craig's2 work in the 1970's. Smith and Cobb3 cite that most of the sources refer to waterflooding oils of viscosity of less than 100 mPaยทs. The major precepts of classical light oil waterflooding have been: start early; and maintain the voidage replacement ratio (VRR). Early start to waterflooding has been examined through the years and confirmed as the best practice for conventional oils by Gulick et al 4 and Ghozali 5. Maintaining even voidage replacement is so ingrained that Canadian producers must get permission from government regulators to deviate the VRR from 1.
- North America > Canada > Alberta (0.51)
- North America > United States > Texas (0.47)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.75)
- North America > United States > Texas > Permian Basin > Midland Basin > BrownField Field > Strawn Formation (0.97)
- North America > United States > Texas > Permian Basin > Midland Basin > BrownField Field > Canyon Formation (0.97)
Abstract Stimulation of weakly cemented formations is not the same fracturing process that occurs in hard rocks because the weak formations have minimal strength and basically zero fracture toughness. It has been demonstrated conclusively that vertical planes can be injected in weakly cemented formations with control of the plane's azimuth, and multiple planes can be injected at differing azimuths, both sequentially and simultaneously in a single well. Laboratory and near-surface experiments involving injection from a perforated casing have yielded random injected geometries that are not repeatable and do not develop a planar-injected feature. On the other hand, if the casing is dilated during the injection process, repeatable consistent vertical planar-injected geometries are formed with control of the azimuth of the injected planes. These experiments have been conducted in laboratories at numerous shallow-field sites involving excavation of the injections and at deeper field sites with the injected geometry determined by real-time imaging using the active resistivity method. The specialized casing system is conventionally drilled and cemented in place, sub-surface resistivity receivers installed, the casing dilated during injection, and the subsequent injected geometry imaged in real-time during the injection process. The application has field demonstrated both simultaneous and sequential multi-azimuth, vertical planar injections from a single casing horizon. The method has significant potential in soft rock formations for production enhancement in both shallow gas and shallow heavy oil reservoirs. This paper presents field injection experiments of multi-azimuth, injected, vertical planar geometries in a variety of weakly cemented formations and describes the application of the method to shallow petroleum soft rock reservoirs, especially for thermal and solvent recovery of heavy oil. Background A series of field experiments in loose sands and peat layers lead to the realization that the azimuth of injected, vertical planes could be controlled by the well initiation device, and that the injected plane would remain on azimuth by controlling the rate of injection and the viscosity of the injected fluid. The ability to control the azimuth orientation of vertical-injected planes in weakly cemented formations was first demonstrated in a number of shallow field trials in 1992. These early experiments were all excavated to determine the orientation and extent of the injected geometry. For a proof of concept project for the U.S. Army Corps of Engineers, 23 injected, vertical planes were constructed at a site in Vermont (Felice and Hocking 1994). A series of vertical planes were constructed at the site, which is a recent river flood plane composed of sands, silts, clay, and gravel. Single and multiple injections were conducted to demonstrate that the technology was capable of controlling vertical plane azimuth orientation, planar extent, thickness, and coalescence. The injected planes were initiated in both dry and saturated conditions with verification of injected geometry based on post-test excavation wherever possible (Fig. 1). By 1996, more than 250 tests were conducted at eight sites in a variety of formations and stress conditions, with the experiments being either excavated or imaged by surface tiltmeters and downhole active resistivity to verify the extent, orientation, and thickness of the resulting vertical-injected, planar geometry (Hocking 1996).
- North America > United States > Texas (0.28)
- North America > United States > Vermont (0.24)
- Europe > Norway > Norwegian Sea (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.88)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Abstract Using acoustic energy in enhanced oil recovery is not a new idea but yet is categorized as an unconventional method. In previous studies at our institution, the effect of ultrasonic radiation on capillary imbibition recovery of light oil from a water wet medium was widely investigated. Upon promising results, the study was extended to more challenging cases such as oil wet matrix (with and without initial water) and heavy oil. The effects of ultrasonic intensity and frequency were also included. Cylindrical sandstone cores were placed into imbibition cells where they contacted with aqueous phase. Each experiment was run with and without ultrasonic radiation keeping all other conditions and parameters constant. The experiments were designed to investigate how the presence of initial water saturation can affect the recovery (Swi=0 to 40%), and also how the recovery changes for different oil viscosities (35 to 1600 cp). Furthermore, the samples were tendered oil-wet by treating with dryfilm to quantify the effects of wettability. In addition, the specifications of acoustic source such as ultrasonic intensity (45 to 84 W/ sq cm) and frequency (22 and 40 kHz) were also changed. An increase in recovery was observed with ultrasonic energy in all cases. This change was more remarkable for oil-wet medium. The additional recovery with ultrasonic energy became lower as the oil viscosity increased. The results revealed that the ultrasonic intensity and frequency are very critical on the performance. This is a critical issue as the ultrasonic waves have limited penetration into porous medium and the intensity reduces while penetrating into porous medium. This is a major drawback in commercializing this promising process for well stimulation. Hence, we designed a set-up to measure the ultrasonic energy penetration capacity in different media, namely air, water, and slurry (sand+water mixture). A one-meter long water or slurry filled medium was prepared and the ultrasonic intensity and frequency were monitored as a function of distance from the source. The imbibition cells were placed at certain distances from the sources and the oil recovery was recorded. Then, the imbibition recovery was related to the ultrasonic intensity, frequency, and distance from the ultrasonic source. Introduction Using acoustic waves as an enhanced oil recovery technique has been of interest in the past decades. The main idea behind these studies was to observe how and to what extend acoustic energy might affect oil recovery. In a pioneering study, Duhon and Campbell (1965) conducted waterflood tests under ultrasonic energy and showed that ultrasonic energy causes an improvement in oil recovery. They also related the ultimate recovery to the frequency. Nosov (1965) observed a decrease in the viscosity of polystyrene solution under sound waves. Chen (1969) and Fairbanks and Chen (1971) reported increase in oil percolation rate through porous medium. Chen (1969) also showed that the effect of heat generated by ultrasonic radiation was minimal on the observed oil recovery increase. Johnston (1971) studied the influence of ultrasound on decreasing polymer viscosity. Cherskiy et al. (1977) described a sharp increase in permeability of core samples saturated with fresh water in the presence of acoustic field. Neretin and Yudin (1981) observed an increase in rate of oil displacement by water through loose sand under ultrasound. Pogosyan et al. (1989) showed that gravitational separation of water and kerosene accelerates due to acoustic field.
- North America > United States > Texas (0.68)
- North America > Canada > Alberta (0.47)
- Research Report (0.46)
- Overview (0.34)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.86)
Abstract This work describes the development of a hydrodynamic and heat transfer mechanistic model for steam flow in a steam injection process. The problem of two-phase steam flow in pipelines and wellbores has been solved recently by using available empirical correlations from the petroleum and nuclear industry by Lopes (1986) and Moura (1991). Despite the good performance achieved by the empirical approach, mechanistic models developed by Ansari (1994), Hasan (1995), Gomez (2000) and Kaya (2001) supports the importance of using the mechanistic approach for the steam flow problem in injection systems. In this study, the methodology to solve the problem consists in the application of a numerical method to the governing equations of steam flow. A marching algorithm is used to determine the distribution of pressure and temperature along the pipelines and wellbores. A computer code has been formulated to get numerical results. These results are compared to results of the main models found in the literature. Finally, when compared to available field data, the mechanistic model for steam flow gives better results than empirical correlations. Introduction Steam injection is a special method of recovery applied generally for very viscous oil reservoirs. This method consists of injecting heat to reduce viscosity and, this way, increase the oil mobility, resulting in an increment in the production of the wells, as defined in Hong (1994). A system of steam generation and injection is shown in Figure 1 and consists basically of a source of steam, distribution lines, injection wells and a discarding tank.
- South America > Brazil > Rio Grande do Norte > South Atlantic Ocean > Potiguar Basin > Estreito Field (0.99)
- North America > United States > Wyoming > Bighorn Basin > Garland Field (0.99)
Abstract It is possible to set a special packer within the long completion horizontal interval to establish an injection zone and a production zone, and a new flooding scheme of simultaneous injection and production in a single-hole horizontal well drilled for developing thin marginal heavy oil reservoir or small block reservoirs or offshore reservoirs. In field practice, the fluids injection rate can be controlled with either concentric or parallel tubing strings. Reservoir numerical simulation was used to determine the formation thickness lower limitation for different viscosity reservoir and the optimum time to start steam flooding after steam soak by economic oil/steam ratio. The optimum time to start steam flooding is at the 7th cycle. There exists a peak recovery efficiency of steam flooding when the length of separation section ratio is 0.15โ0.2. Oil recovery rate can be enhanced by increasing steam injection rate, but pressure difference also increase and the pressure difference increases sharply, and separation section by packer will not be in a stable state in the steam flooding process. A steam injection rate of 2.4t/(d.ha.h) was suitable for steam flooding under practical injection-production conditions. All the results could be useful for the guidance of steam flooding project. Introduction There is formation thickness limitation for vertical production well because of short well completion interval and lower production rate. Thin formation or high viscosity heavy oil reservoir is called marginal for commercial oil production. It will be convenient to make the oil inflow or outflow from the bottom hole of horizontal well because of its long completion interval in the formation (Joshi, 1988; Wang, 1995). Horizontal well is used more often in small block reservoirs or offshore reservoirs for the limitation of well space and cost of well drilling, so, the formation thickness limitation will be extensive for horizontal well, and it will be difficult to hold formation pressure maintenance and production rate for small block reservoirs. It is possible to separate the long completion horizontal interval with special packer for injection and production at same time(Huang et al, 2005). Concentric or parallel tubing strings and packer can be used to separate the horizontal well, and pressure difference of injection and production segment will be affected by the length of well and separated interval and injection rate and production rate. It is a dynamic coupled fluid flowing between reservoir and horizontal bole, segments of injection and production will affect both each other, so it is necessary to consider the pressure difference limitation of the packer for production rate dispatching of horizontal well, and to provide the guidance of field operation. Steamflooding is the following operation processes of steam simulation, the alternation of steam soaking to steamflooding can be used in long completion interval horizontal well after several cycles. This operation scheme will be performed in the same well bore, heat loss from injection tubing strings will be transferred to production tubing strings, and the steamflooding system will keep high thermal efficiency. It is necessary to find a desirable steam soaking cycle for the alternation to steamflooding, and the research on steamflooding operation schemes will be important for the guidance of field application also.
- North America (0.70)
- Asia > China (0.70)
- Europe > Norway > Norwegian Sea (0.24)
Abstract Heavy oil reservoirs are typically not possible to characterize or monitor using seismic methods, since the key acoustic properties of heavy oil namely density and bulk modulus are too similar to those of water. Multi-transient EM (MTEM) is a time-domain dipole - dipole galvanic resistivity mapping technology ideally suited to estimate in situ reserves of heavy oil as well as monitoring of cold and thermal production of heavy oil. All aspects of MTEM data acquisition have been optimized to achieve a sufficiently dense surface sampling in relation to the target depth, and to reach the necessary signal to noise (S/N) at target depth in the shortest time possible with a given source strength. The spatial resolution is sufficient to characterize the total recoverable reserves within a planned Steam Assisted Gravity Drainage (SAGD) project, or within a volume affected by Cyclic Steam Stimulation (CSS), also known as "huff and puff' production. Repeatability of EM data is excellent facilitating monitoring of subtle resistivity changes with good spatial resolution. Several factors affect the resistivity during the monitoring phase. The increased temperature will lower the resistivity by up to 85 % and the changes in resistivity due to changes in water saturation are described by the Archie equation (Archie, 1942). The salinity of the pore water will be diluted when steam condenses to water resulting in a resistivity increase. In addition to these factors, the reservoir also suffers dissolution of grain cement and loss of some of the original mineral volume. At the same time the reservoir expands due to the increased fluid pressure and concomitant reduction in vertical effective stress. This leads to further increases in porosity and permeability, hence also to decreased resistivity and weakening of the bulk and shear moduli affecting the seismic response. Ideally a feasibility study for EM monitoring should be performed based on the results generated by a reservoir simulator, where the dynamic changes in the key parameters: temperature, salinity and the saturations of water, oil, hydrocarbon gas and live steam are tracked for every grid cell over time. This information can then be transformed into resistivity for each grid cell and the EM response from the steam chamber can be modeled at different time steps throughout the planned lifespan of the project. Currently, reservoir simulators cannot incorporate dynamic changes in porosity and permeability that are observed as permanent reductions of the elastic moduli and also reduced resistivity. It is necessary to better understand this so called formation damage to fully describe the evolution of the steam chamber. Introduction In situ production of heavy oil should ideally be preceded by an evaluation of the amount of oil in place. The Canadian government requires a minimum number of exploration wells per block, and drilling followed by wire line logging will provide very accurate information at the well location, but does not provide us with the larger picture regarding the 3D shape of the reservoir and how oil and oil saturation varies throughout the reservoir. Seismic does not detect heavy oil but can be used to map the spatial distribution of sand and shale provided there is a difference in acoustic impedance between the two lithologies, as tends to be the case in the Alberta heavy oil deposits. Electromagnetic information is sensitive to the transverse resistance defined as the product of the resistivity and the thickness of the reservoir. The resistivity as a function of water saturation (Sw) is non-linear described by the nominal trend Sw -2 shown in Figure 1 below, so for a Sw of 0.7 the resistivity is only a factor two larger, and at a Sw of 0.5 only four times as resistive as the 100 % brine saturated reservoir. This means uneconomic low hydrocarbon saturated reservoirs cannot even be detected by EM given the natural background variation in resistivity.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Two characteristics of XSAGD that accelerate bitumen recovery and improve thermal efficiency are discussed in this simulation study. First, it is well understood that the significant oil mobilization process during SAGD occurs at the periphery of the steam chamber where steam transfers heat to the reservoir rock and bitumen. However, once the SAGD steam chamber is well established, it tends to have a low surface area to volume ratio due to its generally cylindrical geometry. In contrast, XSAGD tends to have a higher ratio of surface area to volume once its multiple steam chambers are well established. This allows a given amount of heat injected as steam in XSAGD to contact bitumen faster than the same amount of heat injected in SAGD after the initial steam chamber formation period. Second, fluids moving through the parallel horizontal wells in SAGD follow pathways that remain relatively stable in temperature throughout the life of the operation. Conversely, fluid flow through the perpendicular arrangement of wells in XSAGD exposes cooler portions of the reservoir to conduction heat transfer from hot steam flowing in the injectors or heated bitumen and steam condensate flowing in the producers. This heat transfer accelerates heating in the reservoir and reduces the heat that is produced back to the surface so that more of the injected heat is beneficially applied to the reservoir compared to SAGD. The heated areas close to the wells accelerate the development of lateral displacement pathways promoting more rapid spreading of the steam chambers in XSAGD. The increased thermal efficiency and acceleration of recovery of XSAGD are more pronounced for thinner pay and for lower pressure operation compared to SAGD. However, XSAGD retains some economic advantage even as pay thickens and injection pressure increases.
Abstract Numerical simulation of thermal recovery processes like steam injection often involves localized phenomena such as saturation and temperature fronts due to hyperbolic features of governing conservation laws, Treating more efficiently convective terms could help to diminish spurious oscillation and/or numerical dispersion and better tracking of discontinuity shocks. But in regions near the shock numerical dispersion can only be removed by the use of very fine uniform grids with many grid blocks. To avoid expensive solution of such a finely girded domain, we develop a moving mesh approach combined with higher order up-winding schemes. Numerical solver here have been employed is Finite volume method. A MMPDE(moving mesh PDE) is solved associated with physical PDE's of steam injection process in order to relocates the mesh nodes to concentrate them in regions of sharp discontinuity and Equi-distribute a measure of error-estimate (monitor function) over the meshes. Solution will advance more rapidly on course meshes and fluxes at the coarse-fine grid interfaces are refined to guarantee mass conservation.. Since the region surrounding the sharp discontinuity and requiring high resolution consists of only a small fraction of the entire domain, prescribed locally time stepping results in a great saving in computational time. Specific features of moving mesh methods like monitor-function smoothing, control of mesh widths and readjustment of solutions further to mesh movement are addressed. Numerical experiments are carried out to demonstrate the efficiency and robustness of the proposed method in 1-D and 2-D.However numerical results for moving coordinates are compared with those obtained from simulation on non-adapted mesh framework. Preferences of higher-order solvers over lower-order ones in terms of shock capturing is being investigated.. Although we have limited our modeling to steam flooding process, but simulation demonstrates main features of our approach, applicable to other EOR processes such as VAPEX, SAGD, and In Situ Combustion Process.