Summary A statistical model with a strong correlation has been developed to determine average fracture density (FD) on the basis of production variability of 271 individual wells producing exclusively from the Nikanassin and equivalent formations in a large area of more than 15 000 km2 in the western Canada sedimentary basin (WCSB) in Alberta and British Columbia. Fractional production-variability plots (FPVPs) published by Nelson (2001) have been used successfully in the past in many naturally fractured reservoirs around the world. Up to now, the generation of such graphs has been based on empirical observations from field-production data. The variability of the graphs is interpreted qualitatively as a measure of reservoir heterogeneities. This paper presents a sequential methodology to reproduce empirical fractional variability plots of the Nikanassin tight gas formation using real data, an empirical variability-distribution model (VDM), and dual-porosity numerical simulation. Different simulation approaches and multiple sensitivities were generated from the simplest to the most-detailed cases to understand what causes the curvature of the FPVP in Nikanassin wells. The base simulation case is a homogeneous dual-porosity model, where porosity and permeability are set constant for matrix and fractures. A second case accounts for a heterogeneous dual-porosity model generated through statistical distributions of porosity and permeability. Finally, discrete-fracture-network (DFN) methodology is used to generate multiple fracture models from which stochastic fracture properties are generated for the simulation model. It is concluded that curvature of the variability plot is affected mainly by the occurrence of natural-fracture density. This finding permits estimating FD approximately parallel to the northwest/southeast-trending thrust belt of the Canadian Rocky Mountains in both the west and the east side of the deformation wedge. An unexpected result is that for a significant change in fracture permeability and porosity with constant FD, the fractional production-variability curve is not affected significantly in the case of gas reservoirs. Although the method is applied specifically to the Nikanassin tight gas formation, the theory is developed in detail in such a way that the methodology can be applied in other tight gas reservoirs around the world. Findings from this work are in good agreement with the geological description of the Nikanassin formation and with a production analysis performed in six Nikanassin study areas based on the cumulative number of wells vs. yearly cumulative gas production.
Unconventiona estimated world hat the volum recovery factorTo help unlock fracturing in ho geometry (not state in the dra geomechanical fractured tight g Traditionally, t system to a pla presented in th orientation and pressure deplet are ignored.
Sediment deposition in water reservoirs has major implications for storage capacity, reservoir lifetime, and water quality. Changes in rainfall patterns and land use will consequently alter the rate of erosion and therefore have a direct effect on sedimentation rates. This literature review employed a systematic mapping approach to collate and describe evidence of contemporary sedimentation trends for impounded reservoirs and natural lakes with emphasis on studies which analysed impacts on water storage capacity. Fourteen studies determined an overall increase in sedimentation rate, 13 identified a recent decline and another 5 reported mixed results. Interestingly, 83.3% of the articles that studied natural lakes found an increase in recent contemporary sedimentation, while 54.5% of the articles on impounded reservoirs indicated recent declines in sediment deposition. Land use change was the main causative factor responsible for sedimentation rate increase followed by the combined effects of land activities and climate change. Soil and sediment management strategies, implemented in and upstream of some impounded reservoirs, have proved to be effective in mitigating and remediating reservoir sedimentation. From the 147 papers preselected, only 33 contain sufficient sedimentation data to infer recent rate trends with only about 45% of these articles reporting quantities of storage capacity loss caused by sedimentation. Across these 33 studies, assessments of sedimentation and associated storage capacity loss are compromised by the limited spatiotemporal resolution of current measurement methods, reinforcing the requirement to develop new, more robust techniques to monitor sedimentation and storage capacity changes.
Summary Unconventional gas is stored in extensive areas known as basin-centered continuous-gas accumulations. Although the estimated worldwide figures differ significantly, the consensus among the studies relating to unconventional gas resources is that the volumes are gigantic. However, the low permeability in these types of reservoirs usually results in a very low recovery factor. To help unlock these resources, this paper presents a new and more accurate way of simulating multistage hydraulic fracturing in horizontal wells in three dimensions by use of single- and dual-porosity reservoir models. In this approach, the geometry (not necessarily symmetric) and orientation of the multiple hydraulic fractures are driven by the prevailing stress state in the drainage volume of the horizontal well. Once the hydraulic-fracturing job is accurately modeled in three dimensions, two-way geomechanical coupling is used to history match the produced gas from a horizontal well drilled in the Nikanassin naturally fractured tight gas formation of the Western Canada Sedimentary Basin (WCSB). Traditionally, the most widely used approaches have their roots in semianalytical calculations simplifying the fracturing system to a planar feature propagating symmetrically away from a line source of injection. In contrast, the computed results presented in this study show that the incorporation of geomechanical effects gives a more realistic representation of the orientation and geometry of hydraulic fractures. Reduction in permeability of the natural and hydraulic fractures because of pressure depletion results in more-realistic production predictions compared with the case in which geomechanical effects are ignored. The telling conclusion, in light of the computed results, is that the field of hydraulic fracturing provides an object lesson in the need for coupled 3D geomechanical approaches. The method presented in this paper will help to improve gas rates and recoveries from reservoirs with permeability values in the nanodarcy scale.
In-situ combustion (ISC) is being carried out in the Quifa heavy oil reservoir in Colombia, employing four vertical inner wells and four deviated outer wells (inverted nine-spot pattern). Additionally there are four horizontal wells surrounding the pattern, which started producing one year before the combustion project was initiated. In order to evaluate the project performance key parameters, such as volumetric sweep efficiency and recovery factor must be estimated. Therefore, it is important to have reliable values of drainage area and oil in-place volumes since they are basics for the calculations. Given the complex nature of this reservoir, with a strong water drive, the estimation of the drainage area, oil in place and the recovery factor posed a major challenge. The reservoir is characterized by abrupt permeability and oil saturation changes, resulting in water channeling and well interference. This paper presents the methodology used to obtain the drainage area and current recovery factor of the ISC pilot project by using numerical reservoir simulation. It comprises the generation of oil drainage maps and cross-plots of what we called "Oil Displaced by Neighboring Wells, ODNW" as a function of time. This approach is more accurate than analytical methods for such complex reservoirs since those methods are based on ideal homogeneous reservoir conditions that assume uniform fluid displacement and a symmetrical advance of the combustion front. Results are presented for the oil in place, the drainage area, and the recovery factor at one year of air injection. These results are compared with those derived from analytical methods. The methodology was designed to be readily applicable to similar heavy oil reservoirs worldwide.
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