Reservoir In Alberta Research Articles

Investigation of alkali and salt resistant copolymer of acrylic acid and N‐vinyl‐2‐pyrrolidinone for medium viscosity oil recovery

AbstractHeavy oil reservoirs, unsuited for thermal applications, are being exploited using chemical enhanced oil recovery (CEOR) techniques. The most widely used polymer in CEOR applications is hydrolyzed polyacrylamide (HPAM). However, it hydrolyzes very rapidly under alkaline conditions, making it susceptible for alkaline polymer flooding, the main variant of chemical EOR techniques. To overcome this shortfall of conventional HPAM, a copolymer P(AA‐co‐VP) of acrylic acid (AA) and N‐vinyl‐2‐pyrrolidinone (NVP) was synthesized, that can offer stability and positive synergism against alkali. In the research presented herein, rheological properties of HPAM and P(AA‐co‐VP) were compared in terms of viscosity and elasticity for typical alkali‐polymer (AP) flood operations. The core flooding experiments were conducted using the heavy oil samples collected from a reservoir in Alberta. The shear rheological and dynamic viscoelastic properties of P(AA‐co‐VP) copolymer improved in presence of strong alkali while the conventional HPAM showed much higher viscosity loss, becoming less effective for AP heavy oil recovery operations. In the presence of alkali, 45.9% and 47.3% incremental recovery factor are shown by HPAM and the newly synthesized P(AA‐co‐VP) copolymer. Although the incremental recovery factor shown by newly synthesized polymer is slightly higher, it resulted in a three times lower residual resistance factor than HPAM. Lower residual resistance factor is important for ensuring good transport properties during polymer flooding. AP flooding conducted using P(AA‐co‐VP) copolymer could effectively overcome the drawbacks of conventional HPAM polymer, thereby improving the heavy oil recovery and transport in porous media.

Quantifying seasonal succession of phytoplankton trait‐environment associations in human‐altered landscapes

AbstractIntegration of species traits in direct gradient analysis generates insights into how communities are assembled and may respond to environmental changes. We investigated phytoplankton trait‐environment relationships for over 300 taxa during the open‐water season across 75 north‐temperate lakes and reservoirs in Alberta, Canada. An innovative, data‐driven approach was applied using iterative model selection for RLQ optimization to reveal key monthly associations. Fourth‐corner analysis then tested the significance of relationships using spatially and phylogenetically constrained null models derived by Moran spectral randomization. Both local‐ and regional‐scale drivers of succession were found with evidence of deterministic filtering by traits increasing in mid‐summer. Trait associations to land‐use and water quality highlighted potential anthropogenic cross‐scale interactions, such as logging and pasture development affecting phytoplankton via allochthonous nutrient inputs. Biogeographic factors (e.g., elevation and habitat size) and associated temperature and chemical gradients (e.g., pH and bicarbonate) were also linked to multiple morphological, physiological, and behavioral traits, including potential toxin production. Several correlated traits emphasized importance of trait syndromes corresponding to distinct taxonomic groups (e.g., cyanobacteria and green algae). However, rather than clustering species with shared ecological preferences or roles, our study builds on past trait‐based approaches to phytoplankton by testing for explicit trait associations with a range of environmental factors. Thus, we provide a novel, quantitative means of revealing environmental constraints on communities and translating their compositional changes under climate and other human influences into functional impacts on freshwater ecosystems.

Multiscale drivers of phytoplankton communities in north-temperate lakes.

Multiple factors operating across different spatial and temporal scales affect β-diversity, the variation in community composition among sites. Disentangling the relative influence of co-occurring ecological drivers over broad biogeographic gradients and time is critical to developing mechanistic understanding of community responses to natural environmental heterogeneity as well as predicting the effects of anthropogenic change. We partitioned taxonomic β-diversity in phytoplankton communities across 75 north-temperate lakes and reservoirs in Alberta, Canada, using data-driven, spatially constrained null models to differentiate between spatially structured, spatially independent, and spuriously correlated associations with a suite of biologically relevant environmental variables. Phytoplankton β-diversity was largely independent of space, indicating spatial processes (e.g., dispersal limitation) likely play a minor role in structuring communities at the regional scale. Our analysis also identified seasonal differences in the importance of environmental factors, suggesting a general shift toward greater relevance of local, in-lake (e.g., nutrients and Secchi depth) over regional, atmospheric and catchment-level (e.g., monthly solar radiation and grassland coverage) drivers as the open-water growing season progressed. Several local and regional variables explained taxonomic variation jointly, reflecting climatic and land-use linkages (e.g., air temperature and water column stability or pastureland and nutrient enrichment) that underscore the importance of understanding how phytoplankton communities integrate, and may serve as sentinels of, broader anthropogenic changes. We also discovered similar community composition in natural and constructed water bodies, demonstrating rapid filtering of regional species to match local environmental conditions in reservoirs comparable to those in natural habitats. Finally, certain factors related to human footprint (e.g., cropland development) explained the composition of bloom-forming and/or toxic cyanobacteria more than the overall phytoplankton community, suggesting their heightened importance to integrated watershed management.

Gap Metric Based Performance Assessment of Subcool Control in Steam Assisted Gravity Drainage Wells

Steam assisted gravity drainage (SAGD) is a widely adopted oil extraction technique for heavy oil reservoirs in Alberta, Canada. One of the common approaches by which the producers optimize the production from SAGD reservoirs is by controlling the emulsion level above the producer well bores, a strategy known as subcool control within the industry. In this study, we assess and compare performances of two subcool control strategies, one of which makes use of classic control strategy (PID) and the other is of advanced control strategy (model predictive controller (MPC)). As the controlled process in this case is a non-linear process, we propose a gap metric-based control performance assessment (CPA) method. By this method, the local models as well as their associated weights are determined using the gap metric. We show that the MPC-based strategy outperforms the PID loops-based strategy in subcool control application.

Sustainability Assessment of Power Generation from an Abandoned Oil and Gas Well in Alberta, Canada

The main objective of this paper is to study the sustainability of power generation from an abandoned oil and gas well in the province of Alberta, Canada. Economic and environmental indicators were used for the sustainability assessment. A conceptual design for a pilot plant was developed, and the main parameters were determined. An abandoned oil and gas well represents the thermal power source through circulating water into an organic Rankine cycle (ORC) unit to generate electricity. The thermal power is extracted through a double-pipe heat exchanger configuration installed in an abandoned well and having the benefit of the already erected casing pipe. The ORC unit is with a maximum electric power capacity of 110 kW at water flow rate 22.1 l/s, and water outlet temperature 122°C. The levelized cost of electricity (LCOE) for geothermal power generation from an abandoned well was developed at different values of water outlet temperature in the range 77°C- 122°C and the corresponding LCOE range was 0.10 $/kWh- 0.54 $/kWh. Based on the same water outlet temperature range, a shift of power generation from natural gas to an abandoned well in Alberta would mitigate a range of 8600- 14800 tonnes of CO2 annually. Reservoirs in Alberta with high temperatures more than 150°C are recommended for installation of sustainable geothermal power generation system with large-scale power capacity in megawatts. The efficient high-temperature reservoir would lead to a more feasible, sustainable, and cost-effective system output.

Microseismic monitoring of a tight light oil reservoir: A case history in the Cardium Halo Play, Alberta

The effectiveness of hydraulic-fracturing completions in a tight-oil play is investigated by detailed interpretation of microseismicity. The microseismic programs were acquired in the Cretaceous Cardium light oil sandstone reservoirs in Alberta, Canada. Events with magnitudes between [Formula: see text] and [Formula: see text] are located by downhole monitor wells to a maximum distance of 525 m, enabling inference of the fracture wing length, height, and azimuth based on event distribution. The fracture ports, one per stage, were located in an open-hole configuration that used external packers for zonal isolation. During completions, the ports were opened with ball-actuated frac sleeves. Event distributions indicated that, in some cases, fractures grew preferentially away from the Rocky Mountain deformation front. This inferred that fracture asymmetry is independent of the position of the monitoring array, indicating that it cannot be ascribed to observation bias and suggesting that the direction of fracture growth was dominantly influenced by the preexisting stress conditions in the reservoir. The distribution of microseismicity further indicates that isolated event clusters occur 30–50 m above the reservoir. These out-of-zone events are interpreted to have occurred on unpropped fractures. In comparison with gelled oil or foamed water, slickwater fracturing fluids are shown to produce more diffuse and scattered microseismic expression accompanied by better cumulative oil production. Taken together, the results of these studies indicate that the use of slickwater fracturing fluid, along with the reduced stage spacing and tighter interwell spacing, is expected to lead to higher initial production as well as higher estimated ultimate recovery.

CO2 storage capacity in laboratory simulated depleted hydrocarbon reservoirs – Impact of salinity and additives

A number of depleted hydrocarbon reservoirs in Alberta, Canada provide an opportunity for enhanced CO2 storage density because the reservoir conditions favor CO2 gas hydrate crystal formation. A laboratory simulation study was conducted to study this process and assess the impact of injection method, presence of additives and salinity on the CO2 storage density. Results indicated constant flow rate followed by constant pressure CO2 injection enhanced CO2 hydrate formation compared to constant pressure gas injection. It was noted that 85 % of the original water in the reservoir formed CO2 hydrate after 24 h experiments and that figure rose to 90 % after a 120 h period. Certain amount of tapioca starch and Polyvinylpyrrolidone (PVP) added to the water prevented the hydrate formation in the earlier stage (delay of the onset of hydrate nucleation but subsequently more CO2 was stored as hydrate in the reservoir compared to the inhibitor-free systems. Hydrate formation in saline reservoirs was reduced compared to pure water conditions. The hydrate technology provides an improved CO2 storage density.

Prediction of CO2 solubility in bitumen using the cubic-plus-association equation of state (CPA-EoS)

The ability to accurately predict the solubility of CO2 in bitumen is essential to the design of bitumen and heavy oil recovery processes. We applied the cubic-plus-association equation of state (CPA-EoS) to calculate the solubility of CO2 in bitumen and the Soave–Redlich–Kwong (SRK) equation of state was applied to treat the physical molecular interactions. The proposed thermodynamic model was verified against the experimental data for CO2 solubility in bitumen over wide ranges of temperature and pressure for four different bitumens from Alberta reservoirs. The CPA-EoS was able to predict the solubility with less deviation from the experimental data than the regular cubic equations of state and the statistical association fluid theory (SAFT). Our results suggest that the CPA-EoS is an effective method of conducting solubility calculations for solvent assisted bitumen recovery processes.

Thermal Recovery of Bitumen From the Grosmont Carbonate Formation - Part 1: The Saleski Pilot

Summary The Grosmont formation, a carbonate reservoir in Alberta, Canada, has 400 billion bbl of bitumen resource, which is currently not commercially exploited. The carbonate reservoir is karstified by groundwater and tectonically fractured, resulting in three classes of porosity: matrix, vugs, and fractures. The viscosity of bitumen is lowered by four to six orders of magnitude when heated by steam. Since December 2010, the Saleski pilot project evaluated steam-injection-recovery processes by use of four well pairs, two each in the Grosmont C and Grosmont D units. For the first year of the pilot, two well pairs were operated with continuous injection and production similar to successful steam-assisted-gravity drainage(SAGD) projects in Alberta oil sands. Reservoir observations of steam/oil ratio (SOR) and calendar-day oil rate (CDOR) indicate recovery by gravity drainage is viable, although operating practices from conventional SAGD must be modified for the Grosmont formation. The decision to evaluate cyclic injection and production from single wells was made in early 2012, although it was recognized that cyclic operations created new challenges for the facility (which was built for SAGD operations) and artificial lift. The pilot data indicate that the drilling conditions (balanced vs. overbalanced), completions (openhole vs. slotted liner), and acid treatments of the wells have a significant impact on the individual-well performance. Injectivity into the Grosmont reservoir is high, even into a cold reservoir, because of the existing fracture system. Injection pressures stayed less than 40% of the estimated pore pressure required to lift the overburden. 4D-seismic results indicate that the injection conformance along the well axis is close to 100% and that the heated area is laterally contained around the well. Productivity is comparable to oil-sands project performance. The decline of oil rate is not only dependent on pressure but also on temperature. For cyclic operations, a CDOR of 43 m3/d (for a 450-m-long well) and an SOR of 3.4 were achieved, demonstrating that with sufficient scale, a commercial project can be established successfully. The pilot has satisfactorily derisked the Grosmont reservoir at Saleski. While cyclic operations have demonstrated economic performance, continuous injection and production similar to SAGD remains an alternative recovery strategy beyond startup in the later depletion stage. Successful future developments will advance the optimization of drilling, completion, artificial-lift, and plant capacity issues, while the reservoir itself has demonstrated its production capacity.

Prediction of solubility of CH4, C2H6, CO2, N2 and CO in bitumen

AbstractAn accurate model to calculate the solubility of light hydrocarbons (methane, CH4 and ethane, C2H6) and non‐hydrocarbon gases (carbon dioxide, CO2, nitrogen, N2 and carbon monoxide, CO) in bitumen is required for the optimal design of bitumen and heavy oil recovery processes and transportation. In this work, we used the Krichevsky–Ilinskaya equation to predict the solubility of light solvents (CH4, C2H6, CO2, N2 and CO) in bitumen from five reservoirs in Alberta, Canada. The Peng–Robinson (PR) equation of state (EoS) is used to treat the gas phase. The proposed model is then verified using available experimental solubility data of light solvents in bitumen, and good agreement is observed. The experimental data cover wide ranges of pressures and temperatures. The results show that the proposed model represents the available solubility data of light hydrocarbons (CH4 and C2H6) and non‐hydrocarbon solvents (CO2, N2 and CO) in bitumen with absolute average relative deviations of <4.2% and 5.4%, respectively. These results can be applied to heavy oil and bitumen recovery processes.

Geochemical analyses on bituminous carbonate reservoir in Alberta, Canada: focusing on the GC/GC-MS results of bitumen

The geochemical study on bituminous carbonate reservoir in Alberta has been performed to document the organic geochemical characteristics of the Grosmont Formation using two drilling cores (SAL 03-34 and SAL 08-01), especially focusing on the GC and GC-MS analyses. The results of GC and GC-MS analyses for the extracted organic matter (EOM) showed that all samples have been severely undergone a biodegradation process. However, the GC-MS data have displayed a little variation among the samples, which may be due to degree/type of biodegradation and the type of microbial activity. Triterpane biomarkers are present in low amounts, and steranes in even lesser amounts. Source and maturity assessments from both biomarkers are limited due to the lack of peaks by advanced biodegradation. The demethylated hopanes, which are typical of biodegraded oils, are not seen in these samples but they are apparently not unusual for the Athabasca tar sands, probably due to the specific type of post-emplacement microbial activity. Triterpanes biomarkers illustrate that a highly anoxic hypersaline source environment has contributed to the original oils, at the same time having anoxic marine carbonate/marl character. There is also tenuous evidence for a post-Triassic source according to the tricyclic terpane ratios. The steranes similarly indicate a marine, possibly carbonate-influenced source. Some of the aromatic compounds could also indicate a marine and anoxic hypersaline sourcing. The available peak ratios and patterns of EOM by GC-MS suggest high maturity, and aromatic parameters infer condensate window level with a vitrinite reflectance equivalent range of ∼0.9–1.2%. This could explain the remaining relatively light n-alkanes in the saturated GC chromatograms.

Biodegradation characteristics of bitumen from the Upper Devonian Grosmont reservoir, Alberta, Canada

Abstract The Upper Devonian Nisku Formation, Upper Ireton, and Grosmont Formation (collectively referred as the “Grosmont reservoir”) form a giant bitumen/heavy oil reservoir in Alberta, Canada with about 406 billion barrels of original oil in place. Because of the low quality of the hydrocarbons and the complex geology, the Grosmont reservoir was not deemed commercially viable until relatively recently. The Grosmont is now under consideration for commercial development by several companies and consortia due to technological advances and higher oil prices. One part of the work leading up to new pilot sites is the characterization of the degree of biodegradation in the Grosmont reservoir, which could be used as a proxy of the petrophysical properties of bitumen, specifically viscosity. In order to characterize the biodegradation in the Grosmont reservoir, a total of 18 samples selected from the Nisku, Upper Ireton, and Grosmont along a strike cross-section were examined by gas chromatography-mass spectrometry. Biomarker analysis indicates the Grosmont reservoir was subjected to extreme stages of biodegradation, demonstrated by the loss of regular steranes, strongly biodegraded hopanes, and reduced abundances of tricyclics and diasteranes. The rare geological marker compound 28, 30-bisnorhopane is also highly biodegraded but does exist in some Grosmont bitumen samples examined, supporting the notion that bitumens in the Devonian carbonates and the Cretaceous oil sands have a common origin. Based on the distribution characteristics of hopanes and tricyclics, several biodegradation parameters are identified and the samples are categorized into three distinct biodegradation stages. The data shows that the stage of biodegradation is likely most severe around stratigraphic boundaries and generally increases from southeast to northwest. Several recognized biodegradation parameters, such as 17α(H)-hopane/17α(H)-norhopane, are correlatable with the bitumen viscosity. Such parameters can be used as proxies for in situ viscosity, which is highly useful in aged samples (older than a few years) that have lost volatiles while in storage and thus no longer have the same viscosity as when retrieved from the reservoir.

Study of Alkaline/Polymer Flooding for Heavy-Oil Recovery Using Channeled Sandpacks

Summary For heavy oils with viscosities ranging from 1000 to 10 000 mPa·s in western Canada, primary production and waterflood together can recover only 8–15% of original oil in place (OOIP) at their economic limits because of the adverse mobility ratio, severe water channeling, low reservoir pressure, and formation voidage. These heavy oils usually have a relatively high content of acids that can react with alkalis to form in-situ surfactants. The loosely consolidated sandstone formations in which these oils are deposited are characterized by high porosity, high permeability, and low reservoir temperature. These reservoir conditions are favorable for polymer application. Therefore, there is a potential to improve waterflood in these reservoirs by applying alkaline/polymer (A/P) flooding. This paper presents the results of a laboratory study of A/P flooding for heavy-oil recovery, including viscosity measurements, flood tests conducted in channeled sandpacks, residual-resistance-factor (FRR) determination, and residual-oil-distribution tests. A heavy oil with a viscosity of 1,202 cp and an acid number of 1.07 (mg of KOH/g of oil) and produced brine collected from a heavy-oil reservoir in Alberta are used in this study. We found that the distribution of the injected chemical solution within the high-permeability channels leads to the diversion of the subsequently injected chemical solution to low-permeability zones with higher oil saturation because of the formation of blockage in the channel zones. Consequently, pressure buildup during chemical-slug injection is the key to the improvement of displacement efficiency. Flood tests also show that A/P flooding is more efficient than either alkaline flooding or polymer flooding. The optimal formulation for the heavy oil used in this study is 0.4% NaOH + 0.2% Na2CO3 + 1000 mg/L polymer, with a tertiary oil recovery of 25–30% of OOIP above that from waterflooding. Analysis of the results of the residual-oil distributions in the channeled sandpacks at the end of A/P flooding show that A/P flooding can effectively improve the sweep efficiency of waterflooding for the heavy oil.

Impact of steam trap control on performance of steam-assisted gravity drainage

Steam-assisted gravity drainage (SAGD) is a mature commercial heavy oil and bitumen recovery technology operated by over 10 operators in Athabasca and Cold Lake reservoirs in Alberta. Initially, in Athabasca reservoirs, the in situ oil phase viscosity typically exceeds 1 million cP, yet with heating to over 200°C, the viscosity drops to between 1 and 20cP. The process consists of two parallel horizontal wells: the top one injects steam into the reservoir while the bottom one collects mobilized oil and produces it to the surface. The process is made more thermally efficient by maintaining a liquid pool that surrounds the bottom production well and prevents escape of steam from the steam chamber. This is often referred to as steam-trap control. In field practice, the continued existence of the liquid pool is monitored by examining the temperature difference, known as the interwell subcool, between the injected steam and produced fluids. Typically, the subcool is maintained between 20 and 40°C. Given that there are non-uniformities of the reservoir properties in the downwell direction, there is potential for loss of steam-trap control at one or more locations along the wellbore. In this study, the impact of subcool on the thermal efficiency and performance of SAGD is examined by detailed 3D reservoir simulation. The results show that there is a critical subcool value below which the steam trap fails.

Simulation Study of Underground Coal Gasification in Alberta Reservoirs: Geological Structure and Process Modeling

Underground coal gasification (UCG) as an efficient method for the conversion of the world’s coal resources into energy, liquid fuels, and chemicals has attracted lots of attention in recent years. This paper is concerned with a feasibility study of the UCG process for Alberta reservoirs using the three-dimensional simulation of this process based on a unique porous media approach. The proposed approach combines the effects of heat, mass transport, and chemical reactions to achieve this goal. The Computer Modeling Group (CMG) software STARS is used for simulation. The geological structure including coal and layers interspersed between coal seams (claystone layers), the porosity/permeability variation, and the chemical processes with corresponding parameters are considered in the model. Chemical stoichiometry coefficients of the pyrolysis process are calculated from proximate and extended experimental data. Genetic algorithm and pattern search are used for parameter estimation. This model is developed to study UCG in deep coal seams and can be used for production prediction and optimization of the process. The simulation results, such as cavity formation, temperature profile, and gas composition at the producer, are presented. Finally, the results are analyzed on the basis of field pilot tests.

Factors affecting the chromatographic partitioning of CO2 and H2S injected into a water-saturated porous medium

Acid gas comprising 98% CO2 and 2% H2S has been injected since 2002 in a depleted gas reservoir in Alberta, Canada, that has 20% water saturation. Carbon dioxide broke through first at producing wells, while H2S broke through after CO2. It was hypothesized that the delayed breakthrough of H2S was due to its greater solubility in reservoir water than that of CO2. Static laboratory experiments at in-situ conditions confirmed the higher solubility of H2S in brine than that of CO2. The solubility of the injected gas seems to increase linearly with the mole fraction of H2S in the gas stream; however, due to preferential H2S solubility, the dissolved gas has a greater proportion of H2S than CO2 compared with the injected gas. Dynamic laboratory experiments of the flow of CO2 containing H2S through a 24 m long coil tube packed with silica sand and saturated with brine at in-situ conditions of pressure and temperature have shown that the higher solubility of H2S in contrast to that of CO2 results in suppressed H2S concentrations at the leading edge of the breakthrough gas phase at outlet. Additional laboratory experiments with variable composition of the injected CO2 and H2S stream, and different conditions of temperature, pressure and water salinity have shown that these factors affect the breakthrough of the two gases and the time lag between them. Subsequently, the laboratory experiments were replicated using a compositional numerical simulator. Sensitivity analysis of the numerical simulations has shown that the CO2 and H2S breakthrough at the outlet is affected also by factors affecting the length of the twophase region such as medium relative permeability and flow direction with respect to gravity. Dispersion does not affect the timing of the gas breakthrough, but reduces the lag between the CO2 and H2S breakthrough. The results of these laboratory and numerical experiments should impact injection and monitoring strategies for impure CO2 streams.

Surface Heave Induced by Steam Stimulation in Oil Sand Reservoirs

Abstract Steam stimulation is one of the viable methods to extract heavy oil from oil sand reservoirs in Alberta. In this thermal process, steam is injected into the oil sand reservoir. The oil sand formation expands due to an increase in pore pressure and thermal heating. This expansion results in an upward movement of the overburden, and thus, heaving of the free ground surface. This paper proposes an analytical method to estimate the surface heave induced by steam injection. The method was used to investigate the surface heave profiles under horizontal well injection. It was found that the surface heave profile is governed by the mass and heat transfer and distribution within the oil sand reservoir. The effect of the increase in pore pressure (or decrease in net overburden stress) on the surface heave is also compared to that due to the thermal expansion of the oil sand. The paper also discusses the limitations on the use of surface heave monuments and tiltmeters in monitoring the thermal recovery process. Introduction Thermal recovery processes such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD) involve large volume fluid and steam injection into oil sand reservoirs. Steam injection produces a dilatation of the oil sand reservoir due to an increase in pore pressure and temperature of the reservoir. The overburden containing the reservoir responds to the steam injection by upward heaving of the free ground surface. Surface heave of up to 20 cm has been recorded(1). The profile of the surface heave reflects the distribution of the injected steam within the oil sand formation. Monitoring the surface heave evolution during the steaming operation may be used as an inverse method of monitoring the steam injection operation. This paper presents an analytical method to determine the surface heave profile induced by steam stimulation for a horizontal well. Parametric studies were conducted to investigate the important factors contributing to the surface heave profile. Problem Statement This study considers a steam stimulation operation using a horizontal well. Steam is injected into a horizontal well installed within an oil sand formation of finite thickness (Figure 1). Since the overburden serves as a competent hydraulic barrier to the fluid upward migration, it is assumed that the injected steam is contained within the oil sand reservoir, which results in an expansion of the reservoir. Thus, steam injection using a horizontal well can be treated as a two-dimensional plane strain problem. Figure 1 illustrates the problem statement. The objective of the exercise is to determine the surface heave profile as a function of the amount of steam injected into the horizontal well. Methodology Steam stimulation is a complex thermal hydraulic mechanical multiphase flow process. Determination of injected fluid distribution within the reservoir is not trivial. Since the shale overburden serves as a competent hydraulic barrier to the fluid upward migration, the geomechanical responses in the overburden are governed by the expansion pattern of the oil sand reservoir due to steam stimulation.

In Situ Viscosity of Heavy Oil: Core and Log Calibrations

Abstract Having knowledge of oil viscosity variation within reservoirs would be of considerable benefit when producing from heavy oil fields. Previous work has demonstrated that low field NMR bench-top instruments can be used to perform measurements of in situ viscosity. Ideally, if these measurements could be performed on NMR logging tools, viscosity characterization studies could be carried out using fewer core samples. In this paper, data is presented for a heavy oil reservoir in northern Alberta. A methodology is presented for tuning NMR viscosity estimates to the field in question, and core analysis results are collected, showing that in situ viscosity predictions are possible in the laboratory. NMR spectra measured in the laboratory are compared to NMR logging tool spectra, in order to determine if results obtained using bench-top instruments can be extrapolated to logging tool data. Introduction Canada has significant proven reserves from the oil sands in Saskatchewan and northern Alberta, which constitute some of the largest resource bases in the world. With the decline of conventional oil reserves in Canada, interest is shifting rapidly to the production of this heavy oil. Heavy oil and bitumen are characterized by high fluid viscosity and density values similar to that of water. The high oil viscosity is the single greatest impediment to the successful recovery of this resource, and the viscosity is directly related to both the technical success of any chosen recovery scheme and the economic value of the oil. As a result, oil viscosity information is key when estimating reserves and developing recovery options from heavy oil and bitumen formations. In many heavy oil and bitumen reservoirs in Alberta, and likely all over the world, viscosity may vary significantly with depth and location(1,2). This may be due to biodegradation of the bitumen(2), along with other factors such as supply of micro-organisms to the oil and the solution gas-oil ratio. A result of this viscosity variation is that any chosen thermal or non-thermal enhanced oil recovery option will vary in effectiveness in different parts of the reservoir. Therefore, being able to map viscosity variations, along with proper characterization of rock properties, will also significantly affect the economics and recovery from heavy oil projects. Viscosity is conventionally measured by two different methods(3). Samples are either taken from the produced fluid from the wellhead, or oil sand samples are taken into the laboratory and oil is extracted in order to measure its viscosity. The difficulty in making measurements on wellhead samples is that the oil may have been contaminated by diluents or drilling fluid(3), or may contain significant emulsified water from thermal operations. This means that viscosity values obtained from wellhead oil samples must be used carefully and should be analyzed in order to ensure that they are truly representative of the oil viscosity in the formation. Measurements on bitumen that has been extracted from core samples are generally more accurate, but also tend to be more expensive. Care must be taken to ensure that enough samples are taken to properly characterize the fluid viscosity in the reservoir.

Review of Reservoir Parameters to Optimize SAGD and Fast-SAGD Operating Conditions

Abstract Although high recovery efficiency is expected from the SAGD process, high steam production costs and the substantial volumes of water required have made us focus on more effective recovery methods. One such method is the Fast-SAGD process which utilizes one or more offset horizontal wells parallel to the original SAGD well pair. In these studies, simulations were used to examine the reservoir parameters and operating conditions that need to be in place to optimize the SAGD process. Based on the simulation of a typical Cold Lake reservoir in Alberta, the studies found that relatively clean sand reservoirs with a minimum thickness of 20 m and a vertical permeability of 2.5 Darcy are good candidates for the application of SAGD. Also, reservoirs in a fining upward depositional environment are ideally suited for a SAGD operation. The results of our studies also showed that, for the same operating conditions, Fast-SAGD improved energy efficiency by 24% and productivity by 35% over SAGD. Fast-SAGD is therefore a more efficient recovery process requiring less steam and having lower operating costs to produce the same amount of bitumen. The case of two offset wells located on either side of one SAGD well pair promises the most effective Fast-SAGD configuration, even if a total of six offset wells with a SAGD well pair is still economic compared to the conventional SAGD process. Cumulative bitumen production is increased and at the same time the cumulative steam-oil ratio is decreased as a result of higher thermal efficiency. Introduction Alberta's oil sands contain the largest crude bitumen resource in the world, having approximately 259 billion cubic metres of initial oil in-place and 27.7 billion cubic metres of remaining established reserves (see Tables 1a and 1b)(1). Over 80% of these reserves can be produced only by using in situ recovery methods; therefore, research to find more effective in situ recovery methods is encouraged. The SAGD process has been tested in the field, and is now in a commercial stage of production in Western Canadian oil sands(2). The application of SAGD in various reservoir conditions has been studied, and recently research studies that can not only reduce the steam production cost but also enhance heat efficiency of the SAGD process have been conducted(3). In our studies, the characteristics of the SAGD recovery method were reviewed. In addition, the proper reservoir conditions and optimized operating conditions for the SAGD process were researched by conducting numerical simulation. The possibility of applying the Fast-SAGD process, a modification of the SAGD process(4), was also investigated in comparison to conventional SAGD. Finally, the operating conditions for the optimization of the Fast-SAGD process were studied. Variations of SAGD Process Enhancements The conventional SAGD process is a steam injection recovery method which uses two horizontal wells. In the Peace River area, a small pressure differential between adjacent pattern steam chambers was applied to enhance the SAGD process(5). A steam drive process can be applied to the SAGD operation once sufficient bitumen mobility has been obtained between steam chambers.

Dynamic Economic Indicator To Evaluate SAGD Performance

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 100525, "A Dynamic Economic Indicator To Evaluate SAGD Performance," by H. Shin, SPE, Shell Canada Ltd., and M. Polikar, SPE, U. of Alberta, prepared for the 2006 SPE Western Regional Meeting, Anchorage, 8-10 May. An economic indicator called simple thermal-efficiency parameter (STEP) was developed to evaluate the performance of a steam-assisted gravity-drainage (SAGD) project. A dynamic model called STEP-D was developed for use as an economic indicator under the changing conditions of the economic limit of the instantaneous steam/oil ratio (SOR) and the price of heavy oil. Introduction The economics of a SAGD project is related to several production-performance parameters. The most significant are SOR, cumulative steam/oil ratio (CSOR), ultimate recovery factor (RF), and project life. STEP is based on CSOR, calendar day oil rate (CDOR), and RF for the time corresponding to an SOR of 4. STEP's usefulness as an economic indicator was validated qualitatively as well as quantitatively. STEP was introduced to optimize SAGD operating conditions in Athabasca-, Cold Lake-, and Peace River-type reservoirs in the Alberta oil sands. This economic indicator was modified to evaluate the performance of a SAGD project under selected reservoir parameters and optimal operating conditions. STEP was found to be a useful qualitative as well as quantitative economic indicator in evaluating SAGD performance. In reality, the economics of a thermal project depends strongly on the economic limit of SOR and heavy-oil price, poil. These variable parameters are used in the economic evaluation of field projects. In this research, a dynamic model, STEP-D, was developed for use as an economic indicator under these changing conditions. For the STEP-D calculation, the economic limit of SOR was varied from 3 to 6 and the poil from U.S. $15 to $30/bbl for three oil-sands reservoirs in Alberta. Development of a Dynamic Economic Indicator Initially, STEP was used to evaluate the performance of a SAGD project under optimal conditions. It was pro-posed as a simple economic indicator, to be used instead of net present value (NPV), while determining the best SAGD operating conditions. The simulation results showed that NPV had a linear relationship with RF and CDOR, but a decreasing exponential relationship with CSOR.