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Hruška, Marina (Chevron Energy Technology Company) | Bachtel, Steve (Chevron Energy Technology Company) | Archuleta, Bonny (Chevron Energy Technology Company) | Skalinski, Mark (Chevron Energy Technology Company)
Summary In this integrated study using resistivity images, conventional openhole logs, and core data from a Middle Eastern reservoir, abundance and geometric configuration of bedded and nodular evaporite have been studied to help distinguish which nodular forms of evaporite may be related to a permeability suppression. Several logs have been calculated from the resistivity image log to quantify nodular evaporite and help predict the presence of corresponding core facies well. Compared with thin-section description, most samples of nodular evaporite were exhibiting fine-scale cementation as well, and their permeability was suppressed compared with samples with rare or no fine-scale cementation in thin sections.
Clarkson, C.R.. R. (University of Calgary) | Wood, J.M.. M. (Encana Corporation) | Burgis, S.E.. E. (Encana Corporation) | Aquino, S.D.. D. (University of Calgary) | Freeman, M.. (University of Calgary)
Summary The pore structure of unconventional gas reservoirs, despite having a significant impact on hydrocarbon storage and transport, has historically been difficult to characterize because of a wide pore-size distribution (PSD), with a significant pore volume (PV) in the nanopore range. A variety of methods is typically required to characterize the full pore spectrum, with each individual technique limited to a certain pore size range. In this work, we investigate the use of nondestructive, low-pressure adsorption methods, in particular low-pressure N2 adsorption analysis, to infer pore shape and to determine PSDs of a tight gas silt-stone reservoir in western Canada. Unlike previous studies, core-plug samples, not crushed samples, are used for isotherm analysis, allowing an undisturbed pore structure (i.e., uncrushed) to be analyzed. Furthermore, the core plugs used for isotherm analysis are subsamples (end pieces) of cores for which mercury-injection capillary pressure (MICP) and permeability measurements were previously performed, allowing a more direct comparison with these techniques. PSDs, determined from two isotherm interpretation methods [Barrett-Joyner-Halenda (BJH) theory and density functional theory (DFT)], are in reasonable agreement with MICP data for the portion of the PSD sampled by both. The pore geometry is interpreted as slot-shaped, as inferred from isotherm hysteresis loop shape, the agreement between adsorption- and MICP-derived dominant pore sizes, scanning-electron-microscope (SEM) imaging, and the character of measured permeability stress dependence. Although correlations between inorganic composition and total organic carbon (TOC) and between dominant pore-throat size and permeability are weak, the sample with the lowest illite clay and TOC content has the largest dominant pore-throat size and highest permeability, as estimated from MICP. The presence of stress relief-induced microfractures, however, appears to affect laboratory-derived (pressure-decay and pulse-decay) estimates of permeability for some samples, even after application of confining pressure. On the basis of the premise of slot-shaped pore geometry, fractured rock models (matchstick and cube) were used to predict absolute permeability, by use of dominant pore-throat size from MICP/adsorption analysis and porosity measured under confining pressure. The predictions are reasonable, although permeability is mostly overpredicted for samples that are unaffected by stress-release fractures. The conceptual model used to justify the application of these models is slot pores at grain boundaries or between organic matter and framework grains.
Summary Permeability provides a measure of the ability of a porous medium to transmit fluid and is significant in evaluating reservoir productivity. A case study that compares different methods of permeability prediction in a complex carbonate reservoir is presented in this paper. Presence of siliciclastic fines and diagenetic minerals (e.g. dolomite) within carbonate breccias has resulted in a tight and heterogeneous carbonate reservoir in this case. Permeability estimations from different methods are discussed and compared. In the first part of the paper, permeability measurements from conventional core analysis (CCAL), mercury-injection capillary pressure (MICP) tests, modular formation dynamic tests (MDTs), and nuclear-magnetic-resonance (NMR) logs are discussed. Different combinations of methods can be helpful in permeability calculation, but depending on the nature and scale of each method, permeability assessment in heterogeneous reservoirs is a considerable challenge. Among these methods, the NMR log provides the most continuous permeability prediction. In the second part of the paper, the measured individual permeabilities are combined and calibrated with the NMR-derived permeability. The conventional NMR-based free-fluid (Timur-Coates) model is used to compute the permeability. The NMR-estimated permeability is influenced by wettability effects, presence of isolated pores, and residual oil in the invaded zone. A new modified Timur-Coates model is established on the basis of fluid saturations and isolated pore volumes (PV) of the rock. This model yields a reasonable correlation with the scaled core-derived permeabilities. However, because of the reservoir heterogeneity, particularly in the brecciated intervals, discrepancies between the core data and the modified permeability model are expected.
Summary Steam-assisted gravity drainage (SAGD) is the primary in-situ recovery method for bitumen from the large Athabasca deposit in Alberta, Canada. SAGD field operations encounter a significant decrease in production performance when low-permeability shale barriers are present in the formation. These layers can reduce SAGD performance and impede the growth of the steam chamber. They also significantly limit the percentage of the deposit from which bitumen can be economically recovered with SAGD. The concept of drilling vertical slimholes to create flow paths through barriers was conceived and investigated at Alberta Innovates-Technology Futures (AITF), formerly the Alberta Research Council. The use of slimholes has the potential to significantly increase the amount of recoverable bitumen (reserves) and the rate at which it is produced during SAGD. For shallow reservoirs, the slimholes could be drilled from the surface at a relatively low cost. It is believed that the process can be economically viable after its technical operation has been optimized with improvements in drilling technology, slimhole size and spacing, and enhanced usage of the slimholes in the development of steam chambers above the shale layers. Alternatively, the slimholes could be drilled from the horizontal wellbores (to avoid surface disturbance) as either horizontal slimholes from the producer or as horizontal/vertical slimhole combinations from the injector. The 2D and 3D field-scale numerical simulations were performed by use of reservoir properties and operating conditions based on published information for the MacKay River SAGD operation in the Athabasca deposit. The reservoir depth was 135 m, the initial pressure 500 kPaa, the initial temperature 7.5°C, and the initial oil saturation (SO) 0.8. The simulations explored the effect of vertical slimholes, which were laterally offset 7 m from the horizontal well-pair in reservoirs with and without shale layers or shale lenses. The effects on SAGD performance that were investigated were slimhole cross section (25 cm × 25 cm or 50 cm × 50 cm), the distance between slimholes (12 or 24 m) in the direction parallel to the well pair, the permeability of the reservoir and the vertical slimholes, and horizontal slimholes from the injector or producer. The slimhole cross section represents the disturbed area adjacent to the drilled slimhole and the drilled hole itself and is therefore relatively large. The slimholes were represented as high-permeability vertical channels by use of refined grids. For a reservoir with a continuous shale layer, SAGD performance was improved by vertical slimholes because of the recovery of previously inaccessible oil from above the shale layer, where a secondary steam chamber was formed.
Summary Recent work has shown the potential usefulness of both magnetic-susceptibility and magnetic hysteresis techniques in assessing the effect of fine-grained hematite on permeability, where the hematite was dispersed in the matrix of relatively tight gas red sandstone samples. The present study demonstrates that grain lining hematite cement is also a major controlling factor on permeability in a relatively tight gas sandstone reservoir in the North Sea. Magnetic susceptibility measurements on core plugs in this reservoir showed a strong correlation with probe permeability. Moreover, samples with a higher content of hematite exhibited lower permeability values. Thin-section analysis revealed the presence of a thin (approximately 10 to 15 μm) rim of hematite cement surrounding quartz grains, which block pore connections and reduce permeability. Magnetic hysteresis measurements on representative samples indicated a similar paramagnetic clay content in both the low and high permeability samples, suggesting that the clay (mainly illite) is not the dominant controlling factor that produces the variations in permeability that we observed. Because samples with higher hematite content exhibit lower permeability, it appears that hematite is a major control on the permeability variations seen in this reservoir. Although the paramagnetic clays undoubtedly have an influence on the absolute permeability values (increasing paramagnetic clay content has previously been shown to correlate with decreasing permeability), small amounts of grain lining hematite cement can reduce the permeability significantly further. Analysis of the magnetic hysteresis parameters on a Day plot indicated that the permeability was essentially independent of the hematite particle size for the fine particle sizes observed in this study.
Cokar, Marya (Department of Chemical and Petroleum Engineering, Schulich School of Engineering, University of Calgary) | Kallos, Michael S. (Department of Chemical and Petroleum Engineering, Schulich School of Engineering, University of Calgary) | Gates, Ian D. (Department of Chemical and Petroleum Engineering, Schulich School of Engineering, University of Calgary)
Summary In cyclic steam stimulation (CSS), steam is injected above the fracture pressure into the oil-sands reservoir. In early cycles, the injected steam fractures the reservoir, creating a relatively thin dilated zone that allows rapid distribution of heat within the reservoir without excessive displacement of oil from the neighborhood of the wellbore. Numerical reservoir-simulation models of CSS that deal with the fracturing process have difficulty simultaneously capturing flowing bottomhole-pressure (BHP) behavior and steam injection rate. In this research, coupled reservoir-simulation (flow and heat transfer) and geomechanics models are investigated to model dynamic fracturing during the first cycle of CSS in an oil-sands reservoir. In Alberta, Canada, in terms of volumetric production rate, CSS is the largest thermal recovery technology for bitumen production, with production rates equal to approximately 1.3 million B/D in 2008. The average recovery factor from CSS is between 25 and 28% at the economic end of the process. This implies that the majority of bitumen remains in the ground. Because the mobility of the bitumen depends strongly on temperature, the performance of CSS is intimately linked to steam conformance in the reservoir, which is largely established during steam fracturing of the reservoir in the early cycles of the process. Thus, a fundamental understanding of the flow and geomechanical aspects of early-cycle CSS is critical. A detailed thermal reservoir-simulation model, including dilation and dynamic fracturing, was developed, with the use of a commercially available thermal reservoir simulator, to understand their effects on BHP and injection rate. The results demonstrate that geomechanics must be included to accurately model CSS. The results also suggest that the reservoir dilates during steam injection as the result of increases in reservoir temperature, which lead to thermal dilation and higher pore pressure.
Summary The Schoonebeek heavy-oil field was first developed by Nederlandse Aardolie Maatschappij B.V. (NAM) in the late 1940s. Because of economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity-assisted-steamflood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors, and 4 observation wells). Steam injection and cool-down cycles subject a cement sheath to some of the most severe load conditions in the industry. Wellbore thermal modeling predicted that surface and production sections would experience temperatures in excess of 285°C (545°F) and considerable stress across weak formations. A key design requirement was long-term integrity of the cement sheath over an expected 25- to 30-year field life span. Complicating this requirement was the need for lightweight cementing systems, because lost-circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone. The long-term integrity challenge was divided into chemical and mechanical elements. Prior research on high-temperature cement performance by the operator provided necessary guidance for this project. Laboratory mechanical and analytical tests were conducted to confirm the high-temperature stability of the chosen design. In addition to using lightweight components, foaming the slurry allowed the density, mechanical, and economic targets to be met. A standardized logistical plan was put in place to allow use of the same base blend for the entire well, adjusted as needed, using liquid additives, and applying the foaming process when necessary. This single-blend approach greatly simplified bulk-handling logistics, allowing use of dedicated bulk-handling equipment. The first well was constructed in January 2009; all 73 wells have been successfully cemented to surface. The steaming process, initiated in May 2011, has progressed with no well integrity issues to date.
Abstract The reliability of the estimated parameters in well test analysis depends on the accuracy of measured data. Early time data are usually controlled by the wellbore storage effect. However, this effect may last for the pseudo-radial flow or the boundary dominated flow. Eliminating this effect is an option for restoring the real data. Using the data with this effect is another option that can be used successfully for reservoir characterization. This paper introduces a new technique for interpreting the pressure behavior of horizontal wells and fractured formations with wellbore storage. A new analytical model describes the early time data has been derived for both horizontal wells and horizontal wells intersecting multiple hydraulic fractures. Several models for the relationships of the peak points with the pressure, pressure derivative and time have been proposed in this study for different wellbore storage coefficients. A complete set of type curves has been included for different wellbore lengths, skin factors and wellbore storage coefficients. The study has shown that early radial flow for short to moderate horizontal wells is the most affected flow regime by the wellbore storage. For long horizontal wells, the early linear flow is the most affected flow regime by the wellbore storage effect. The most important finding in this study is the ability to run a short test and use the early time data only for characterizing the formation. This means there is no need to run a long time test to reach the pseudo-steady state. Therefore, from the wellbore storage dominated flow, the early radial and pseudo-radial flow can be established for horizontal wells and hydraulic fractured formations. A step-by-step procedure for analyzing pressure tests using the analytical models (TDS) and the type curves is also included in this paper for several numerical examples.
Abstract Transverse fractures created from horizontal wells are a common choice in tight and shale gas reservoirs. Previous work has shown that proppant pack permeability reduction due to non-Darcy flow in a transverse fracture from a horizontal well causes significant reduction in the fracture performance when the gas formation permeability exceeds 0.5 md. There are other configurations and architectures such as aligning the well trajectory with the fracture, either by drilling horizontal wells in the direction that results in longitudinal fractures or by just sticking with drilling vertical wells. However, when drilling and fracturing costs are considered, productivity is not the only optimization consideration. The field example illustrates a case when the apparent choice to use transverse fractures from horizontal wells proved to be suboptimal from the productivity perspective, but fundamental considering economics. Parametric studies for permeability ranging from 0.01 to 5 md illustrate the importance of economics in addition to physical performance. For similar reservoir characteristics, the optimum fractured well architecture varies considerably, and therefore an extensive reservoir engineering approach may be necessary beyond the well completions and/or current prejudices and inadequate understanding.
Turkey, S.. (KOC) | Al-Kanderi, J.. (KOC) | Kumar, P.. (KOC) | Al-Alawi, G.. (Target Oilfield Services) | Al-Hashmi, S.. (Target Oilfield Services) | Al-Harthy, A.. (Target Oilfield Services) | Al-Raisi, M.. (Target Oilfield Services)
Abstract This paper presents the main steps of rock-typing workflow and the technique applied to estimate permeability. Reservoir rock typing (RRT) is a process of up-scaling detailed geological and petrophysical information to provide more accurate input for 3D geological and flow simulation models. The reservoir rocks that correspond to a particular rock type should have similar rock fabric, pore types and pore throat size distribution. The study integrated multi-scale data types to develop a robust and predictable rock type scheme. This consists of detailed sedimentological description of depositional environment and associated sedimentary features, detailed numerical petrographic analysis of rock texture, grain types, porosity types and rock mineralogy and petrophysical data grouping using openhole log and core plugs porosity-permeability relationship and pore throat size distribution (MICP). The main objective was to develop a reliable reservoir rock type scheme that captures the heterogeneity in Jurassic carbonate reservoir for the Middle Marrat Formation in South East Kuwait area and implementation of the RRT to the permeability prediction within the field. Integration of the thin sections, porosity-permeability, pore throat size and distribution has resulted in the identification of reservoir rock types. A total of 14 different rock types were identified within the reservoir interval in the cored wells, which is subsequently grouped into eight due to modelling limitation. The RRT up-scaling was done in a way to minimize the impact of grouping on permeability and saturation computations. The prediction success between the cored RRT and the predicted RRT using openhole data is more than 85%. As a result, the permeability computation success between core plugs and computed permeability using the RRT is more than 80%.