Clarkson, Christopher R. (University of Calgary) | Wood, James (Encana Corporation) | Burgis, Sinclair (Encana Corporation) | Aquino, Samuel (University of Calgary) | Freeman, Melissa (University of Calgary)
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 poresize 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 siltstone 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 stressrelease 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.
Feali, Mostafa (University of New South Wales) | Pinczewski, Wolf (University of New South Wales) | Cinar, Yildiray (University of New South Wales) | Arns, Christoph H. (University of New South Wales) | Arns, Ji-Youn (University of New South Wales) | Francois, Nicolas (Australian National University) | Turner, Michael L. (Australian National University) | Senden, Tim (Australian National University) | Knackstedt, Mark A. (Digitalcore)
It is now widely acknowledged that continuous oil-spreading films observed in 2D glass-micromodel studies for strongly water-wet three-phase oil, water, and gas systems are also present in real porous media, and they result in lower tertiary-gasflood residual oil saturations than for corresponding negative spreading systems that do not display oil-spreading behavior. However, it has not yet been possible to directly confirm the presence of continuous spreading films in real porous media in three dimensions, and little is understood of the distribution of the phases within the complex geometry and topology of actual porous media for different spreading conditions. This paper describes a study with high-resolution X-ray microtomography to image the distribution of oil, water, and gas after tertiary gasflooding to recover waterflood residual oil for two sets of fluids, one positive spreading and the other negative spreading, in strongly water-wet Bentheimer sandstone. We show that, for the positive spreading system, oil-spreading films maintain the connectivity of the oil phase down to low oil saturation. At similar oil saturation, no oil films are observed for the negative spreading system, and the oil phase is disconnected. The spatial continuity of the oil-spreading films over the imaged volume is confirmed by the computed Euler characteristic for the oil phase.
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.
Hruška, Marina (Chevron Energy Technology Company) | Bachtel, Steven (Chevron Energy Technology Company) | Archuleta, Bonny (Chevron Energy Technology Company) | Skalinski, Mark (Chevron Energy Technology Company)
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.
Using a breakthrough process, which does not require microbes to be injected, more than 100 microbial enhanced-oil-recovery (MEOR) treatments were conducted from 2007 to the end of 2010 in oil- producing and water-injection wells in the United States and Canada. On average, these treatments increased oil production by 122%, with an 89% success rate. This paper reviews the MEOR process, reviews the results of the first 100+ treatments, and shares what has been learned from this work. Observations and conclusions include the following:
MEOR can be applied to many more reservoirs than thought originally with little downside risk. This review of more than 100 MEOR well treatments expands the types of reservoirs in which MEOR can be applied successfully. Low-risk and economically attractive treatments can be accomplished when appropriate scientific analysis and laboratory screening are performed before treatments.
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 NMRestimated permeability is influenced by wettability effects, presence of isolated pores, and residual oil in the invaded zone. 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.
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 lm) 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.
Oil and water production data are regularly measured in oilfield operations and vary from well to well and change with time. Theoretical models are often used to establish the production expectation for different recovery processes. A performance surveillance understanding can be developed by comparing the field production data with the production expectation. This comparison generates quantitative or qualitative signals to determine whether the producer meets production expectations or the producer is underperforming and appropriate operational action is required to address the underperformance. The case study is for the South Belridge diatomite in California. This hydraulically fractured diatomite reservoir is currently under waterflood and steamflood. A methodology is proposed to establish the production expectation from historical production data. For primary depletion, the formation linear and bilinear flow models are applied to producers with vertical hydraulic fractures. For waterflood, an analytical method derived from the Buckley-Leverett displacement theory is used. Those analytical methods can predict production and provide surveillance signals for producers in the primary and waterflood recovery stages. For steamflood, a semiquantitative performance/surveillance criterion is proposed on the basis of understanding the mechanistic oil banking concept and reservoir simulation results for steamflood and waterflood. With those models representing expected production performance, an integrated flow regime diagram is proposed for production surveillance. A performance expectation can be developed for an individual producer. A significant overperformance relative to the expectation normally indicates changes in the recovery mechanism or improvement in sweep efficiency. A significant underperformance usually signifies an operational issue that requires correction to optimize the production performance. In the case study, the surveillance methodology for producers under primary depletion, waterflood, or steamflood is demonstrated by use of historical production data. In addition, water channeling between injectors and producers and its impact on production performance are discussed. On the basis of this surveillance methodology, some operational actions were proposed, and successful results are demonstrated. Examples of forecast for an individual producer in the primary depletion stage and field scale prediction in the waterflood stage are provided. Application indicates that the proposed methodology can serve as a convenient and practical tool for reservoir surveillance and operational optimization.
For ultratight shale reservoirs, wettability strongly affects fluid flow behavior. However, wettability can be modified by numerous complex interactions and the ambient environment, such as pH, temperature, or surfactant access. This paper is a third-phase study of the use of surfactant imbibition to increase oil recovery from Bakken shale. The surfactant formulations that we used in this paper are the initial results that are based on our previous study, in which a group of surfactant formulations was examined--balancing the temperature, pH, salinity, and divalent-cation content of aqueous fluids to increase oil production from shale with ultralow porosity and permeability in the Middle Member of the Bakken formation in the Williston basin of North Dakota. In our previous study, through the use of spontaneous imbibition, brines and surfactant solutions with different water compositions were examined. With oil from the Bakken formation, significant differences in recoveries were observed, depending on compositions and conditions. Cases were observed in which brine and surfactant (0.05 to 0.2 wt% concentration) imbibition yielded recovery values of 1.55 to 76% original oil in place (OOIP) at high salinity (150 to 300 g/L; 15 to 30 wt%) and temperatures ranging from 23 to 120°C. To advance this work, this paper determines the wettability of different parts of the Bakken formation. One goal of this research is to identify whether the wettability can be altered by means of surfactant formulations. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale and to examine the viability of a field application. In this paper, through the use of modified Amott-Harvey tests, the wettability was determined for cores and slices from three wells at different portions of the Bakken formation. The tests were performed under reservoir conditions (90 to 120°C, 150- to 300-g/L formation-water salinity), with the use of Bakken crude oil. Both cleaned cores (cleaned by toluene/methanol) and untreated cores (sealed, native state) were investigated. Bakken shale cores were generally oil-wet or intermediate-wet (before introduction of the surfactant formulation). The four surfactant formulations that we tested consistently altered the wetting state of Bakken cores toward water-wet. These surfactants consistently imbibed to displace significantly more oil than brine alone. Four of the surfactant imbibition tests provided enhanced-oil-recovery [(EOR) vs. brine water imbibition alone] values of 6.8 to 10.2% OOIP, incremental over brine imbibition. Ten surfactant imbibition tests provided EOR values of 15.6 to 25.4% OOIP. Thus, imbibition of surfactant formulations appears to have a substantial potential to improve oil recovery from the Bakken formation. Positive results were generally observed with all four surfactants: amphoteric dimethyl amine oxide, nonionic ethoxylated alcohol, anionic internal olefin sulfonate, and anionic linear a-olefin sulfonate. From our work to date, no definitive correlation is evident in surfactant effectiveness vs. temperature, core porosity, core source (i.e., Upper Shale or the Middle Member), or core preservation (sealed) or cleaning before use.
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 x 25 cm or 50 cm x 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.