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Numerous technical papers have been published on the reservoir evaluation of tight sand gas in recent decades. It is believed that tight sand gas is characterized by low permeability, complex pore structure, abnormal pressure, and low gas saturation. Researchers have characterized tight gas in terms of, for example, statistics; and some of them are increasingly interested in the effect of fluid pressure and pore structure on gas saturation. However, there is still a lack of effective experimental and mechanism analysis.
The focus of this paper is to investigate the effect of two factors on controlling the tight gas saturation. A method was proposed for determining the in-situ injection pressure of the DB 2 gas reservoir in the Kuqa area during the gas-accumulation period, and the result was 1.2 MPa. A polyetheretherketone carbon-fiber core holder (maximum temperature 180°C, maximum confining pressure 30 MPa) was designed for the microcomputed-tomography (CT) simulation experiment. After that, four physical simulation experiments of different fluid pressures (0.1, 0.5, 1.5, and 5.0 MPa) were implemented using X-ray CT and the new core holder to study the effect of fluid pressure and pore structure on gas saturation.
The results show that the fluid pressure and micropore connectivity are important factors for gas-saturation increase; the number of gas clusters (connected pores containing gas) increases with the increase of fluid pressure and the maximum volume of gas clusters increases with the increase of pore connectivity. The connected pores with the largest volume are an important source of gas-saturation contribution. The three types of modes (the blowing balloon mode, stitching mode, and composite mode) of microscopic gas-cluster formation are discussed. The blowing balloon mode is key to gas-saturation growth in the period of low fluid pressure or the early stage of the injection process. The stitching mode is key to gas-saturation growth in the period of high fluid pressure or the late stage of the injection process.
The above research system investigates the quantitative control of fluid parameters (pressure) and reservoir parameters (pore structure) on gas saturation, which might change the situation where previous research was too focused on the pore-structure and fluid-pressure characterization, with a lack of quantitative control analysis of reservoir gas saturation. It provides a valuable reference and framework for the reader to conduct further quantitative research on tight gas saturation.
Nejadi, Siavash (University of Calgary) | Kazemi, Nasser (University of Calgary) | Curkan, Jordan A. (University of Calgary) | Auriol, Jean (Université Paris-Saclay) | Durkin, Paul R. (University of Manitoba) | Hubbard, Stephen M. (University of Calgary) | Innanen, Kristopher A. (University of Calgary) | Shor, Roman J. (University of Calgary) | Gates, Ian Donald (University of Calgary)
The oil and gas industry, operating and service companies, and academia are actively searching for ways to look ahead of the drill bit while drilling to reduce the risks and costs of the operation and improve the well-placement process. Optimal drilling in challenging and highly heterogeneous reservoirs, where geological data cannot adequately constrain high-frequency variations in rock properties, requires reliable subsurface information from around and ahead of the drill bit. To provide this, we have developed a seismic-while-drilling (SWD) imaging algorithm using signal processing, drillstring modeling, and prestack wave-equation migration.
To extend the visibility ahead of the bit, we use the drill bit as a seismic source and image the changes in acoustic properties of rocks both around and ahead of the drill bit. The common practice is to build reverse vertical seismic profile (R-VSP) gathers. Here, we use a blind deconvolution algorithm to estimate the drill-bit source signature from the data directly. Alternatively, we can estimate such a signature through drillstring modeling and surface measurements (i.e., hookload and hook speed). The drillstring dynamics are modeled and analyzed using Riemann’s invariants and a backstepping approach in a field-verified model. Next, we enter the estimated source signature into the prestack wave-equation depth-imaging workflow. Our simulations show that providing the drill-bit source signature to the prestack wave-equation depth migration consistently delivers reliable subsurface images around and ahead of the drill bit.
The output of our workflow is a high-resolution subsurface image, which is then applied to provide vital information in oil-sands reservoirs for placement of steam-assisted-gravity-drainage (SAGD) well pairs. Compared with conventional practices, the proposed methodology images around and ahead of the drill bit enable interactive decision making and optimal well placement. The key feature of the presented methodology is that instead of cross correlating the SWD data with the pilot trace and building R-VSP gathers, we use the estimated drill-bit source signature and deliver high-resolution prestack depth-migrated images.
Through numerical modeling, we tested the potential impacts, validity, and challenges of the proposed methodology in drilling horizontal wells in SAGD settings with an emphasis on the McMurray Formation. We further compared the results with the conventional drilling practice. In contrast to existing tools that have limited depth of penetration, interpreting SWD data in real time confidently maps key target features ahead of the drill bit. This imaging workflow provides sufficient time to precisely control the borehole trajectory and stay within the desired reservoir zone. Accordingly, it mitigates the risk of intersecting mudstone-filled channels and lean zones.
Reliable assessment of petrophysical, compositional, and mechanical properties is critical and yet challenging for formation characterization of organic-rich mudrocks. The formation evaluation results are the key to build an accurate geological model and are the starting point for reservoir characterization. This paper aims to (a) develop a method to integrate an iterative formation evaluation workflow with geological modeling and (b) improve the reliability of field-scale geological modeling by reducing the average relative error and uncertainty in well-log-based estimates of petrophysical and geochemical properties using the integrated workflow.
The first step includes joint inversion of well logs to obtain depth-by-depth estimates of formation properties such as porosity, fluid saturations, total organic content (TOC), and volumetric concentrations of minerals, which are inputs to the well-log-based rock classification algorithm. Then the model parameters are updated in each rock-class and the multi-mineral analysis results are cross validated with core measurements in wells where core measurements are available. The iterative procedure is repeated until agreement with core data is achieved. We use the geostatistical analysis to extend the workflow obtained in the cored wells to the neighboring non-cored wells where the developed model in each rock class is reliable. Finally, we use the well-log-based estimates of the petrophysical and geochemical properties as an input to the geological model to estimate reservoir properties such as original-hydrocarbon-in-place.
We successfully applied the method to more than 300 wells in the Midland Basin. Results showed that the average relative error in well-log-based estimates of porosity and water saturations, improved by 22% and 35%, respectively, compared to a conventional non-iterative, non-integrated method which results in 76% improvement in the calculated hydrocarbon-in-place. A sensitivity analysis was performed to evaluate the impact of optimizing and calibrating the model parameters throughout the basin to reduce average relative error and uncertainty in well-log-based estimates of porosity and water saturation, as key petrophysical inputs to the geological model. Results indicated that applying a South Midland Basin TOC model to a North Midland Basin well, causes 56% and 16% increase in average relative error in estimates of water saturation and porosity, respectively, which results in 47% increase in average relative error of original-oil-in-place calculations.
Coupling the integrated formation evaluation workflow, geostatistical analysis, and geological modeling is a novel approach that not only incorporates formation heterogeneity and spatial variations of reservoir properties, but also yields dependable reservoir characterization by quantifying the uncertainty associated with hydrocarbon-in-place estimation. This method enables a reliable field-scale formation characterization in the Midland Basin which is critical for field development planning in organic-rich mudrocks.
Paronish, T. J. (National Energy Technology Laboratory / Leidos Research Support Team) | Toth, R. (West Virginia University) | Carr, T. R. (West Virginia University) | Agrawal, V. (West Virginia University) | Crandall, D. (National Energy Technology Laboratory) | Moore, J. (National Energy Technology Laboratory / Leidos Research Support Team)
The Marcellus Shale Energy and Environmental Laboratory (MSEEL) consists of two project areas within the dry gas producing region of the Marcellus shale play in Monongalia County, West Virginia. MSEEL is a collaborative field project led by West Virginia University, with Northeast Natural Energy LLC, several industrial partners, and sponsored by the US Department of Energy National Energy Technology Laboratory. The study areas are drilled approximately 8.5 miles apart to better understand the vertical and lateral changes in stratigraphy over a short distance. Two vertical pilot wells, MIP-3H and Boggess 17H were drilled in the fall of 2015 and spring of 2019, respectively. Core was recovered from the MIP-3H (API: 47-061-01707-00-00) 112 feet (34m) between depths of 7445 to 7557 feet, and from the Boggess 17H (API: 47-061-01812-00-00) 139 feet (42m) between depths of 7908 and 8012 ft. A full suite of triple combo (gamma ray, neutron, density logs), image logs, and advanced logging tools were run in both wells and calibrated to core analysis. Core analysis includes medical computed tomography (CT) scans, mineralogy and chemostratigraphy determined from handheld X-Ray fluorescence (hhXRF) and X-Ray powder diffraction (XRD) measurements, and determination of total organic content (TOC).
Lithofacies were determined at core-scale using traditional core description techniques and medical CT-scan images. Log-scale facies are based on mineralogy and TOC data and developed using petrophysical logging data calibrated to core data (XRD and pyrolysis data). Chemostratigraphic analysis utilized hhXRF data to determine the major and trace element trends in the cores.
In the two wells six shale lithofacies were recognized at the core and log scale. Both wells show organic-rich facies (TOC > 6.5%) primarily in the middle and lower Marcellus, with a slight decrease in thickness of this interval in the Boggess 17H. This interval is interpreted as an increase in paleo-productivity (increased Ni, Zn, and V), decreased sedimentation (decreased detrital proxies), and anoxic to euxinic conditions (increased Mo and chalcophile elements). Paleo-redox conditions in both wells are dynamic throughout deposition transitioning between euxinic/anoxic to dysoxic/oxic. This trend is seen through elemental proxies and calcite/pyrite concretion distributions.
A key component of an unconventional reservoir development is 3D characterization. A necessary precursor for any seismic inversion work is an inversion feasibility study. We shall demonstrate a best practice inversion feasibility workflow that has several key components: regional geology, petrophysics, rock physics, and geophysical analysis. The study shows an integrated approach using spatially diverse well data to cover the entire Delaware Basin, focusing on Avalon and Bone Springs formations. The results show the ranking of petrophysical properties that contributes to the changes in elastic properties. A good relationship was established between TOC, vclay and porosity to elastic logs using both conventional and unconventional RPMs. A class-IV AVO response was observed in the Avalon formation. Finally, our analysis showed that a depth trend based 1D Bayesian classification using bandlimited log data was able to separate organic rich high TOC facies from siltstones and carbonates. To conclude, an integrated approach involving geology, petrophysics, rock physics and inversion feasibility study increased our understanding of the basin and set path for further analysis. The results from inversion feasibility can be used to understand what facies and how much resolution can be resolved from an inversion which is further used to guide the drilling direction and landing zones. The workflow outlined in this study potentially can lead to a 3D inversion analysis, reservoir property estimations from seismic, TOC mapping and finally for finding sweet spots and better drilling/landing zones in the subsurface.
Unconventional oil and gas production have increased dramatically in the last decade, and in the U.S., the Permian Basin is the most prolific of all the basins. The Delaware Basin located in the western part of the Permian Basin has become one of the most active drilling sites with multi-stacked plays (Mire et al. 2017). Most of the production comes from the Permian-aged Avalon, Bone Springs and Wolfcamp formations. These formations are comprised of a heterogeneous mixture of organic rich mudrocks, siltstones and carbonates (Nester et al., 2014). Due to the complex nature of these rocks, it is advantageous to understand and extract useful information from available data resources from all disciplines. Hence, a collaboration to perform an integrated approach between different disciplines is crucial to effectively find solution for complicated technical challenges in the Delaware Basin (Hoang et al., 2019; Anantharamu and Del Moro, 2019).
The knowledge of geology and petrophysical analysis enhances our understanding of the basin and its mineral constituents. A proper rock physics analysis is extremely important for establishing a link between elastic properties and reservoir parameters, which can later be extrapolated to 3D domain using seismic and inversion workflows.
Understanding the impact of diagenesis on reservoir quality is key to successful production in unconventional reservoirs. Core samples of basinal shales and mixed carbonate-siliciclastic strata of the Lower Permian Wolfcamp and Bone Spring Formations in the Delaware Basin were studied from five wells in Loving and Reeves Counties, Texas. The purpose of this study is to construct a detailed paragenetic sequence and provide new insights into the burial and thermal history of the basin. Petrographic observations, in conjunction with δ13C and δ18O isotope and fluid inclusion data, reveal a complicated diagenetic history consisting of thirty-two major diagenetic events. The earliest diagenetic features were developed during shallow burial and include the formation of phosphatic and calcitic concretions, pyrite framboids, replacive dolomites, compacted fractures, and the cementation of primary pores by calcite. Vertical compacted fractures (Set I) are slightly depleted in δ18O (−4.89 to −2.54‰) and δ13C (−1.35 to +0.95‰) and characterized by irregular to ptygmatic fracture planes, suggesting early formation in incompletely lithified strata. Later stages of fracturing included the formation of calcite beef, horizontal fractures with blocky calcite, steeply dipping subvertical fractures from Set II, and the inclined subvertical fractures from Set III. Bedding-parallel veins of calcite ‘beef’ and blocky calcite are confined to the overpressured interval in the Wolfcamp. They correspond to the lowest δ18O values in this study (−7.56‰ mean) and show pronounced positive excursions in δ13C (up to +4.91‰), which are interpreted to reflect formation at maximum burial conditions and during the production of thermochemical methane. Calcite-filled vertical fractures (Set II and Set III) postdate the bedding-parallel veins and correspond to more negative δ13C (−4.07 to +2.56‰) and less negative δ18O (−8.17 to –3.72‰) values. Homogenization temperatures record a decrease in temperature of about ∼25–30°C between the formation of horizontal veins and Set II fractures. This drop in temperature is interpreted to have, in part, resulted from late Cretaceous to Neogene regional uplift, which was also responsible for creating the fractures associated with Set II and Set III. The occurrence of secondary liquid hydrocarbon inclusions along healed microfractures within calcite beef indicate that the main phase of hydrocarbon migration postdated beef formation. Homogenization temperatures of cements containing primary hydrocarbon inclusions yielded temperatures of around ∼90–95°C. Late stage diagenesis was characterized by the widespread replacement of carbonates by authigenic minerals (i.e. ferroan dolomite, albite, silica, and pyrite), creation of secondary porosity by dissolution, and the emplacement of bitumen. These events appear to have been coeval with smectite–illite conversion, the maturation of organic matter, and thermochemical sulfate reduction. The occurrence of secondary moldic and vuggy porosity filled with bitumen suggests that the more favorable reservoir quality coincides with areas affected by the replacement of siliceous skeletons by authigenic calcite and dolomite, which were later subjected to dissolution by organic acids.
Yupu, Fu (Sinopec Petroleum Exploration and Production Research Institute) | Xuejie, Qin (Sinopec Petroleum Exploration and Production Research Institute) | Chuanxi, Liu (Sinopec Petroleum Exploration and Production Research Institute) | Dongling, Xia (Sinopec Petroleum Exploration and Production Research Institute) | Xia, Yin (Sinopec Petroleum Exploration and Production Research Institute)
The realization of Triassic Yanchang 7 member shale resource potential in Ordos basin is a significant exploration success within the last few years, and the tight sandstone, in the upper section of Chang 7 member received much of the drilling focus as horizontal development expanded in Ordos basin. In order to discuss the prospecting potential of shale oil in Chang 73 sub-member, South Fringe of Ordos Basin, organic geochemical parameters, quantitative characterization of different occurrence oil and assessment for Shale oil potential producibility have been carried out, based on core observation, microphotographs, Rock-Eval pyrolysis, thermovaporization in different temperature ranges and etc. The results indicate that the shale system in Chang 73 sub-member is a high-quality source rock with stable distribution, medium degree of thermal evolution, high TOC content and good kerogen types. Three different lithological associations are identified according to lithology, TOC and mineral content, and thereby a series of key parameters are calculated including total oil content, free oil content and its ratio that normalizes free oil content to total oil content, OSI index. In conclusion, zone 2, composed of tuffaceous fine-grained sandstone and mudstone, is characterized by "high total oil content, high free oil content and its ratio, high OSI index and high physical properties", which proves the favorable target for shale oil, whereas zone 1 is characterized by high total oil content but relative low free oil content and OSI Index; for zone 3, both total oil content and free oil content are much lower than the other two lithological associations.
These years shale oil resource has been explored and developed on an industrial scale in North America, which lead the revolution of shale oil in the world. As the second sedimentary basin in China, Ordos basin is enrichment with oil and gas. The Yanchang formation in late Triassic is one of the most important oil-bearing systems and the Triassic Chang 7 source rocks are regarded as target interval during shale oil exploration and development. Due to technological advance, horizontal wells and stimulated reservoir volume (SRV) has been developed and applied in the depression area, targeting at tight sandstone in the upper section of Chang 7 member (Chang 71 and Chang 72 sub-member). A huge exploration success is achieved and individual wells have got high production. As a result, four pilot development regions are chosen and built, which revealed a good potential of shale oil resource in the central basin (Fu et al., 2019). In order to accelerate the exploration process in the south of Ordos basin, two appraisal wells have been drilled and good oil show is encountered in the bottom of Chang 7 member (Chang 73). And meanwhile two existing wells, such as J-3 and J-4, are chosen to test productivity through CO2 coupled fracturing technology and hydro-fracturing technology, both of which are landing in the lower organic-rich shales. J4 is stimulated to yield oil flow with an average rate of 8.3t/d, and cumulative oil production is approaching to 1700t, while J-3 has got a lower productivity through CO2 coupled stimulating. Though systematic core wells and productivity tests have provided solid foundations for further study, however, exploration and development for lacustrine shale system in china is still in its infancy, compared with 30 years’ technical research and actual practices for American marine shale system(Li, 2017).
FAN, X. (SINOPEC Exploration & Production Research Institute) | Huang, Z. (SINOPEC Exploration & Production Research Institute) | Liu, Z. (SINOPEC Exploration & Production Research Institute) | Zhang, J. (SINOPEC Tech. Houston) | Ji, Y. (SINOPEC Exploration & Production Research Institute)
The Upper Triassic Xujiahe formation is very tight formation located in highly tectonically stressed zones in the Western Sichuan Basin of China. The second and fourth members (abbreviated as T3X2 and T3X4, respectively) of the Xujiahe formation are gas-bearing tight sandstones. Bedding planes and natural fractures with low deviations are developed in the sandstones. This tectonically active in-situ stress state and the low angle natural fractures make the hydraulic fracture to propagate either horizontally or vertically but with small fracture height, which are unfavorable for enhancing gas production.
Multidisciplinary data from the field and experiments were used to determine the in-situ stress state. Minifrac test data were analyzed to determine the minimum horizontal stress. The FMI logging and stress polygon method were used to constrain the maximum horizontal stresses. The differential strain analysis was also performed to measure the principal stresses. A series of laboratory tests were conducted to determine the influences of in-situ stresses and natural fractures on hydraulic fracture propagations. The cohesions and internal friction angles of the bedding cracks were obtained by direct shearing tests using the downhole cores of T3X2. To imitate preexisting low angle fractures in the laboratory tests, man-made fractures were cut and then cemented in the outcrop rock samples, and the true tri-axial fracturing experiments were conducted in these samples to analyze the effects of in-situ stress state on the hydraulic fracture propagation in the tight sandstone.
The following are the results obtained in this paper: (1) The T3X2 reservoirs are in the strike-slip faulting stress state, which is beneficial to generate vertical hydraulic fractures; while the T3X4 reservoirs are close to the reverse faulting stress state where the hydraulic fracture height might be lower than that in the T3X2 reservoirs; (2) The true tri-axial fracturing experiments under the conditions of the in-situ stress states of the T3X2 and T3X4 reservoirs show that the hydraulic fracture geometry is mainly composed of the vertical fractures accompanying with few horizontal fractures. When the ratio of the overburden stress to the minimum horizontal stress is less than 1.2, hydraulic fracture opens or slides along the low angle natural fracture and may form a limited fracture height as a result; (3) The hydraulic fracturing target should be selected at the intervals that have the lowest horizontal stress, and the intervals having low angle natural fractures should be avoided. The pad fluid with high viscosity guar fluid is recommended to use to initiate the main vertical hydraulic fracture.
This study provides an integrated method and a guide for evaluating and designing the stimulation of the Xujiahe tight gas reservoirs in the Western Sichuan Basin. This method may be applicable to similar reservoirs.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Austin, Texas, USA, 20-22 July 2020. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract The publicly available multi-terabyte dataset of the Marcellus Shale Energy and Environmental Lab (MSEEL) consortium provides a unique opportunity to develop fracture models and analyze the effectiveness of the stimulation of a reservoir on a consistent base. Sonic, microresistivity image and production logs, microseismic data, and raw fiber optic measurements are examples of such data. Abundant core samples supplied demonstrate reservoir complexity and high density of natural fractures. The planar fracture model allows us to compare and contrast multiple stimulation strategies and propose engineered completions that cannot be done solely by data-driven approaches. Conclusions about stage spacing, stimulation design, wellbore placement, and stage isolation are shared. The workflow will be detailed to allow others to use, verify, and critique our findings using the same initial data.
Wang, Wenguang (School of Geosciences, China University of Petroleum) | Lin, Chengyan (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum) | Lin, Jianli (School of Geosciences, China University of Petroleum) | Zhang, Xianguo (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum) | Dong, Chunmei (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum) | Ren, Lihua (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum)
The purpose of this paper is to use 3D compaction numerical simulation method to study the sandstone porosity evolution and high-value porosity area in the few well areas of offshore oilfields. These sandstones are located in the central inversion structural belt of the Xihu sag, East China Sea Basin. Based on geological data, seismic data, log data, thin section, scanning electron microscopy, cathode luminescence, bulk X-ray diffraction analysis, powder particle size analysis and routine core analysis, this study used compaction numerical simulation method to reconstruct the porosity evolution of different grain size sandstones in the fourth (H4) and fifth (H5) members of the Oligocene E3h Formation in the study area. Three aspects of research were carried out, including the distribution model of 3D grain size sandstones, mechanical compaction and chemical compaction parameters, 3D porosity evolution and high-value porosity areas. It was determined that there was no correlation between the porosity compaction loss and quartz cement content in different grain size sandstones in the H4 and H5 members, indicating that chemical compaction did not inhibit mechanical compaction. The mechanical compaction and chemical compaction were simulated separately. Different grain sizes sandstones had different mechanical compaction and chemical compaction porosity reductions. The porosity reductions of medium sandstone, sandy conglomerate and fine sandstone by mechanical compaction were 25.3%, 21.81% and 25.97%, and those by chemical compaction were 0.82%, 1.08% and 0.42%, respectively. The sandstone compaction stages of the H4 and H5 members under different tectonic stages were investigated. In the first phase of the slow subsidence stage, the reservoir temperature of the H4 and H5 members were less than 70°C, and these sandstones were in the stage of mechanical compaction. In the second phase of the slow subsidence stage, the reservoir temperature range of the H4 and H5 members were 70°C–114.63°C and 70°C–120.47°C, respectively; these sandstones entered the coexistence stage of mechanical compaction and chemical compaction. From the rapid subsidence stage to regional steady subsidence stage, the reservoirs temperature ranges of the H4 and H5 members were 114.63°C–159.7°C and 120.47°C–167.05°C, respectively; these sandstones were in the stage of chemical compaction dominated- mechanical compaction supplemented. Finally, the differences of sandstone compaction and porosity between the H4b-6 and H5-6 submembers and in the same layers were analyzed. By integrating sedimentary lithologies, porosity evolution, and reservoir "sweet spot" evaluation criteria, the spatial distribution of favorable areas in the H4b-6 and H5-6 submembers were determined. This study is of theoretical significance to elucidate the compaction characteristics, porosity evolution and high-value porosity area distribution in deep and ultra-deep clastic rocks, and also has reference value for the optimization of the tight sandstone favorable areas.