Thick Shale Research Articles

Micro- to nano-scale areal heterogeneity in pore structure and mineral compositions of a sub-decimeter-sized Eagle Ford Shale

Mineral and organic matter compositions & pore structures of fine-grained shale influence reservoir properties. To improve the understanding of spatial heterogeneity in core-sized samples, methods of microscale X-ray fluorescence (μXRF) mapping, (ultra-) small-angle x-ray scattering [(U)SAXS] and wide-angle X-ray scattering (WAXS) have been used to determine elemental, pore-structure variations at scales up to ~10 cm on two samples prepared at circular and rectangular orientations from a piece of Eagle Ford Shale outcrop in South Texas, USA. In addition, thin section petrography and field emission-scanning electron microscopy observations, X-ray diffraction (XRD), total organic carbon, and pyrolysis were utilized to investigate the potential spatial heterogeneity of pore types, mineral and organic matter compositions for cm-sized samples at both orientations. Overall, the siliceous‑carbonate mineral contents in these two samples (8 cm × 8 cm × 0.08 cm and 5 cm × 8 cm × 0.08 cm, in terms of width×length×thickness) of carbonate-rich Eagle Ford Shale vary between laminations at mm scales. For the circular sample, porosity and specific surface area (SSA) variations range from 0.82 to 3.04% and 1.51 to 14.1 m2/g, respectively. For the rectangular sample, values for porosity and SSA vary from 0.93 to 2.50% and 3.95 to 10.8 m2/g. By analyzing six selected sub-samples on each of two samples with (U)SAXS and XRD techniques, nm-sized pores are mainly interparticle ones in the higher calcite regions, where the porosity is also relatively lower, while the lower calcite regions consist of both interparticle and intraparticle pore types with higher porosity. Finally, the μXRF and (U)SAXS mappings are combined to generate porosity distribution maps to provide more insights about sample heterogeneity related to the laminations and fractures at our observational scales.

Assessment of Fault Sealing in the Gabo Field, Niger Delta, Nigeria

This research assesses the sealing of the fault bounded stratigraphy of the Gabo Field, Niger Delta, Nigeria. Materials used comprises of 3D seismic volume in seg-y, ditch cuttings and well logs. The methods applied are standard fault plane evaluation techniques and they include seismic interpretation, well correlation, XRD analysis, and application of the Yielding et al., (1997) shale gouge ratio (SGR) algorithm for fault seal analysis. The tectonic framework was interpreted in terms of deformational, depositional and post-depositional structures. The order of magnitude of stress is SHmax > σv > Shmin. The juxtaposed strata relationships were analyzed by taking cross sections A-A1 and B-B1 and this showed the structural framework across the field. Cross section A-A1 showed that the depositional and post depositional structures are pinchouts (channel abandonment or switching) and shale smears respectively. The cross section B-B1, showed that the deformational structures are faults F1 and F2 – recognized as closely spaced normal faults and F3 is a syn-depoitional growth fault. The well correlation showed the vertical stratigraphy of the wells are comprised of cyclic succession of sands and shales and the shale thickness increased in intermediate sections. The X-ray diffraction (XRD) analysis of the shales showed that the predominant minerals are kaolinite, rutile, gypsum, albite, microcline and quartz. The rock property analysis showed that the net to gross ranges from 26.28 – 82.0% with an average of 73.7%. The volume of shale ranges from 18 – 73.72% with an average of 63.59%. The bulk density of the shales ranges from 2.379 – 2.692g/cc with an average of 2.46g/cc. The total porosity ranges from 0.159 – 0.317 with an average of 0.167 in the shales and 0.272 in the sand. The effective porosity range from 3.58 – 22.71 with an average of 6.028 in the shale and 20.13 in the reservoir. The drawdown mobility and temperature range is 2.2 – 4124.4mD/cP and 63.3 – 80.1oF respectively, while the average is 569mD/cP and 70.63oF respectively. The estimated pore pressure ranges from 0.4213 – 0.4762psi/ft with an average of 0.47psi/ft in the shales and 0.428 psi/ft in the sand. The fault seal analysis showed that the shale gouge ratio range from 0.2 – 0.7 and the stratigraphic juxtapositions are predominantly sand to sand, sand to shale and shale to shale. The results of this research reduces the fault seal uncertainty in the planning of oilfield development projects and enhanced pressure support for the recovery of bypassed hydrocarbons, most especially in compartmentalized reservoirs. In addition, the results of this research can be applied to similar deltaic successions around the world.

Enrichment characteristics and exploration directions of deep shale gas of Ordovician–Silurian in the Sichuan Basin and its surrounding areas, China

The enrichment characteristics of deep shale gas in the Ordovician Wufeng–Silurian Longmaxi formations in the Sichuan Basin and its surrounding areas are investigated through experiments under high temperature and high pressure, including petrophysical properties analyses, triaxial stress test and isothermal adsorption of methane experiment. (1) The deep shale reservoirs drop significantly in porosity and permeability compared with shallower shale reservoirs, and contain mainly free gas. (2) With higher deviatoric stress and axial strain, the deep shale reservoirs have higher difficulty fracturing. (3) Affected by structural location and morphology, fracture characteristics, geofluid activity stages and intensity, deep shale gas reservoirs have more complicated preservation conditions. (4) To achieve the commercial development of deep shale gas reservoirs, deepening geological understanding is the basis, and exploring reservoir simulation technology befitting the geological features is the key. (5) The siliceous shale and limestone-bearing siliceous shale in the Metabolograptus persculptus–Parakidograptus acuminatus zones (LM1–LM3 graptolite zones) are the high-production intervals for deep shale gas and the most favorable landing targets for horizontal drilling. Deeps water areas such as Jiaoshiba, Wulong, Luzhou and Changning with deep shale reservoirs over 10 m thickness are the most favorable areas for deep shale gas enrichment. It is recommended to carry out exploration and development practice in deep-water shale gas areas deposited deep with burial depth no more than 5000 m where the geological structure is simple and the shale thickness in the LM1–LM3 graptolite zone is greater than 10 m. It is better to increase the lateral length of horizontal wells, and apply techniques including high intensity of perforations, large volume of proppant, far-field and near-wellbore diversions to maximize the stimulated deep reservoir volume.

Characterization of the Lower Cretaceous Shale in Lishu Fault Depression, Southeastern Songliao Basin: Implications for Shale Gas Resources Potential

Large thickness of shales over 180.0 m was developed in the source rocks of the Shahezi and Yingcheng formations in the Lishu Fault Depression. Moreover, the high amount of gas content and the total hydrocarbon value of gas logging in several boreholes illustrate that there is a great potential of shale gas resources in this region. Therefore, an integrated characterization of shales from the lower Cretaceous Shahezi and Yingcheng formations was provided to evaluate shale gas resources potential. The measurement results illustrated that the organic-rich shale samples with kerogen type Ⅱ during high to over thermal maturity had a higher content of brittle minerals (>50%) and clay mineral dominated by illite. The shales had a total porosity of 3.11–4.70%, a permeability of 1.24 × 10−3–1.52 × 10−3 μm2, and possessed pore types including dissolution pores, inter-layer pores of clay minerals, micro-fractures, intra-granular pores, and organic pores, which were dominated by micropores and mesopores (0.5–1.7 nm, 2.2–34.3 nm) with a significant contribution from OM and clay minerals. According to the N2 adsorption isotherms, the pore volume was comprised primarily of mesopores with mean widths of 4.314–6.989 nm, while the surface area was comprised primarily of micropores with widths in ranges of 0.5–0.8 nm and 1.0–1.7 nm. Thus, the shales have a suitable porosity and permeability, indicating that fine storage capacity and favorable gas flow capacity occur in the Shahezi and Yingcheng formations, which exhibit a good reservoir quality and excellent exploration potential since the considerable thickness of shales could form a closed reservoir and served as cap rocks for in situ gas generation and accumulation. Especially, according to the measured CH4 excess adsorption amount and the calculated maximum absolute adsorption capacities of CH4 based on the Langmuir adsorption model, the estimated GIP values (1.388–3.307 m3/t) of the shales happened to be in a sampling depth under geological hydrostatic pressure and temperature conditions. This means that the shale storage capacity and high gas content from well site desorption completely met the standard of industrial exploitation when synthetically considering the GIP model. As a consequence, shales in the Shahezi and Yingcheng formations in the Lishu Fault Depression could be potential targets for shale gas exploration.

Oil-bearing evaluation of different lithofacies in Da’anzhai Member, Central Sichuan Basin: implications for shale oil development

The Jurassic Da’anzhai Member of the Sichuan Basin has good prospects in shale oil exploration and development. However, the lack of research on the relationship between different lithofacies and oil-bearing property restricts the research on the geological theory and further exploration and development of shale oil in Da’anzhai Member. Based on core, fluorescence thin sections, rock pyrolysis, total organic carbon (TOC), extraction of chloroform bitumen ‘A’, and nuclear magnetic resonance (NMR) tests, the oil-bearing characteristics and reservoir physical properties in different lithofacies of Da’anzhai Member were analyzed. The results suggest that the oil-bearing and physical properties of shale are better than shell limestone and their peperite. The crude oil discharge from thick shale is limited because of the petrophysical property difference. The Da2b layer thick shale has the best shale oil exploration and development potential, which is the focus of the next step.

Aptian−Albian extension in Tethyan rifted continental passive margin of Tunisia inferred from sequential restorations of balanced cross-sections and expansion index

This article presents an overview of regional extensional deformation across the north-facing southern Tethyan continental passive margin of Tunisia during the Aptian and Albian syn-rift stages. Because of the Late Eocene, Late Miocene and Pleistocene orogenic overprinting, the earlier extensional history of the Tunisian Atlassic province had to be reconstructed from balanced and sequentially restored transects across four key fault systems active at the time. These were used to (i) estimate the amount and timing of extension and (ii) calculate the expansion index (EI) for each fault system. The analysis demonstrates the region experienced a very significant amount of mid-Cretaceous extension, representing the last of several Permian-Mesozoic rift events. Two closely linked styles of deformation were recognised: thick-skinned basement involved faulting and shallow listric faulting detached on decollement surfaces within late Triassic evaporites. Both styles of faulting triggered salt diapirism.Sequential pre-orogenic restorations of a transect across the Tebaga Kebili and Orbata faults in the southern part of this province suggest both experienced a large amount of extensional displacement during the Aptian and Albian (Aptian-Albian extension = 2.6 km), recorded by footwall erosion, growth strata, rollover structures and changes in sedimentary facies. A similar restoration across the Labaiedh (M'rhila-Cherichira) fault system further north, identified both thick and thin-skinned extensional movement associated with diapiric growth and salt extrusion reaching a maximum during the Aptian (Aptian-Albian extension = 0.55 km). A pre-Tertiary restoration of the Teboursouk fault system in the northern part of the province, demonstrated thick-skinned extension peaking during the Albian (Aptian-Albian extension = 0.4 km). This accommodated a thick sequence of basinal shales to the north, deformed by active diapirism with sea-floor salt extrusion, triggered by deep basement faulting and enhanced by the plastic incompetent character of the thick shale dominant overburden.Regional extension across the Tunisian Atlassic province during the Aptian-Albian was contemporaneous with a significant change in intra-plate stress across northern Africa, the opening of the South Atlantic and structural reorganization along the East African continental margin. This synchroneity across such a wide region may reflect some still poorly understood deep crustal processes, ultimately responsible for reactivating older rift faults and regional tilting across the province. The associated gravity salt gliding and diapirism bear comparison with the post-rift deformational style of the South Atlantic passive margin. However intra-evaporite decollement surfaces were more local, limited by active thick-skinned faulting with diapirism typically soft linked to deeper fault movement.

Sedimentology and Geochemistry of the Upper Permian Linghao Formation Marine Shale, Central Nanpanjiang Basin, SW China

The Upper Permian Linghao Formation marine shale and contemporaneous transitional shale are the most potential shale gas targets in the Nanpanjiang basin, which is characterized by considerable TOC content, wide distribution, and considerable shale thickness. On the basis of division in Linghao Formation, petrographic, mineralogical, and high-resolution geochemical analyses were integrated to reveal the sedimentary environment including paleoproductivity, paleoredox conditions, detrital influx, paleoclimate, and the paleosalinity. There are two organic-rich shale intervals in Linghao Formation, which are Ling 1 member and the lower Ling 3 member. The lower Ling 1 is dominated by deep-water shelf facies, which are characterized by high TOC value (0.93%–6.36%, avg. 2.43%), high detrital influx proxies (Zr, 746–1508 ppm, avg. 1093 ppm; Ti, 19278–128730 ppm, avg. 16091 ppm), relatively warm–humid paleoclimate condition (CIA*, 75.94-91.90, avg. 82.26), low paleosalinity proxies (Sr/Ba, 0.13-0.34, avg. 0.22), and high paleoproductivity (P/Al (10−2), 1.06-2.06, avg. 1.63; Mn/Ca (10−3), 27.37-291.69, avg. 128.07). Detrital influx including gravity flow plays a critical role in the enrichment of organic matter. The sedimentary environment of upper Ling 1 and lower Ling 3 is the same as that of lower Ling 1. Unlike lower Ling 1, these intervals are characterized by low detrital influx proxies, moderate weathering, and relatively high paleosalinity proxies. The volcanic ash of Emei volcanism and felsic volcanism in South China plays a critical role in the enrichment of organic matter in upper Ling 1 and lower Ling 3, respectively. The sedimentary models for Linghao Formation organic-rich shale can reveal factors controlling the enrichment of organic matter.

Concurrent 17. Presentation for: Resource potential of the Carrara Sub-basin from the deep stratigraphic well NDI Carrara 1

Presented on Wednesday 18 May: Session 17 NDI Carrara 1 is a deep stratigraphic well completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI), in collaboration with Geoscience Australia and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a newly discovered depocentre in the South Nicholson Region. The well intersected Proterozoic sediments with numerous hydrocarbon shows, likely to be of particular interest due to affinities with the known Proterozoic plays of the Beetaloo Sub-basin and the Lawn Hill Platform, including two organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones. Alongside an extensive suite of wireline logs, continuous core was recovered from 283.9 m to total depth at 1750.8 m, providing high-quality data to support comprehensive analysis. Presently, this includes geochronology, geochemistry, geomechanics and petrophysics. Rock-Eval pyrolysis data demonstrate the potential for several thick black shales to be a source of hydrocarbons for conventional and unconventional plays. Integration of these data with geomechanical properties highlights potential brittle zones within the fine-grained intervals where hydraulic stimulation is likely to enhance permeability, identifying prospective Carrara Sub-basin shale gas intervals. Detailed wireline log analysis further supports a high potential for unconventional shale resources. Interpretation of the L210 and L212 seismic surveys suggests that the intersected sequences are laterally extensive and continuous throughout the Carrara Sub-basin, potentially forming a significant new hydrocarbon province and continuing the Proterozoic shale play fairway across the Northern Territory and northwest Queensland. To access the presentation click the link on the right. To read the full paper click here

Characteristics and controlling factors of transitional shale gas reservoirs: An example from Permian Shanxi Formation, Daning-Jixian block, Ordos Basin, China

The shales in the 2nd Member of Permian Shanxi Formation (Shan2 Member) at the Daning-Jixian block at the eastern margin of the Ordos Basin were deposited in a marine–continental transitional environment. The Shan23 sub-member, which is the target interval for transitional shale gas exploration and development in China, is characterized by substantial shale thickness, few and thin interlayers. This interval, however, has been rarely investigated for reservoir characteristics, especially the controlling factors of high-quality reservoirs. In this paper, the reservoir characteristics and main controlling factors of high-quality reservoirs in Shan23 in the Daning-Jixian block were systematically discussed by organic geochemical analysis, mineral compositional analysis, and microscopic reservoir characterization. The results indicate that the lagoon facies shale interval in the upper part of the Shan23 sub-member has a high total organic carbon (TOC) content, a high brittle mineral content, and high BET surface area and BJH pore volume values, indicating that this is the sweet spot for shale gas exploration and development. Pore space in the Shan23 sub-member shale is dominated by clay mineral intercrystalline pores (76.9%), which also contains organic matter pores (18.7%). The SEM observations reveal that the mineral components are different in pore size distribution (PSD) and the organic matter pores and calcite dissolved pores are mainly in meso-scale, the pores in clay minerals and quartz are in meso- and macro-scale, while the pores in feldspar and pyrite exhibit a wide and uniform size distribution. The single-factor analysis shows that the clay mineral content is the dominant factor controlling pore development in the Shan23 sub-member transitional shales, the TOC content has a certain effect on pore development, and the kerogen type has no discernible effect on pore development.

Resource potential of the Carrara Sub-basin from the deep stratigraphic well NDI Carrara 1

NDI Carrara 1 is a deep stratigraphic well completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI), in collaboration with Geoscience Australia and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a newly discovered depocentre in the South Nicholson Region. The well intersected Proterozoic sediments with numerous hydrocarbon shows, likely to be of particular interest due to affinities with the known Proterozoic plays of the Beetaloo Sub-basin and the Lawn Hill Platform, including two organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones. Alongside an extensive suite of wireline logs, continuous core was recovered from 283.9 m to total depth at 1750.8 m, providing high-quality data to support comprehensive analysis. Presently, this includes geochronology, geochemistry, geomechanics and petrophysics. Rock-Eval pyrolysis data demonstrate the potential for several thick black shales to be a source of hydrocarbons for conventional and unconventional plays. Integration of these data with geomechanical properties highlights potential brittle zones within the fine-grained intervals where hydraulic stimulation is likely to enhance permeability, identifying prospective Carrara Sub-basin shale gas intervals. Detailed wireline log analysis further supports a high potential for unconventional shale resources. Interpretation of the L210 and L212 seismic surveys suggests that the intersected sequences are laterally extensive and continuous throughout the Carrara Sub-basin, potentially forming a significant new hydrocarbon province and continuing the Proterozoic shale play fairway across the Northern Territory and northwest Queensland.

Sedimentary Environment and Enrichment of Organic Matter During the Deposition of Qiongzhusi Formation in the Upslope Areas—A Case Study of W207 Well in the Weiyuan Area, Sichuan Basin, China

For a more in-depth analysis on the marine chemical condition during the earliest Cambrian, mechanism of organic matter enrichment and exploration potential of shale gas resources, based on the petrology, organic geochemistry, and elemental characteristics of the W207 Well, this study discuss the Early Cambrian paleo-ocean environment and factors controlling of organic matter enrichment during the deposition of black strata Qiongzhusi Formation in the upslope areas, southwestern Sichuan Basin, Yangtze Block, China. The sedimentary cycles show that during the depositon of fine-grained Qiongzhusi Fm, interactive cycles of multiple deep-water and shallow-water shelf developed, and were controlled by the rise and fall in sea level. In particular, the slope turbidite (fan) and gravity flow sediments indicate that the shallow-water shelf facies were dominant in the upslope area (SW Sichuan Basin), where not in deep water for a long time, and the sedimentary thickness of the organic rich black shale was limited. Evidence from organic geochemistry indicates that the organic matter of the Qiongzhusi Fm from the W207 Well was mainly of type I kerogen, with a high degree of thermal evolution, little residual hydrocarbon, and low capacity for hydrocarbon generation. The redox parameters indicate that the marine environment on the upslope was medium restrictive, with some upwelling. The seawater had undergone a transformation according to anoxic–oxidic. Therefore, paleo-ocean productivity in the upslope area was generally low, and exhibited a prominent downward trend from bottom to top. Given its high risk of exploration, the authors suggest that the direction of shale gas resource evaluation should change to the intracratonic sag (downslope) area, which is characterized by deep-water shelf facies.

Sedimentary characteristics and lithofacies paleogeography of the Cambrian in Sichuan basin, Southwest China

Cambrian in Sichuan basin developed thick black shale, varies carbonate and clastic rock, which deposited in different sedimentary environment. Sichuan basin in the upper Yangtze platform contained a record of environment during the Cambrian. Detail facies analyses of Cambrian enable us to discuss the sedimentary environment and palaeogeographic setting. Sedimentation commenced in the Early Cambrian with the deposition of shelf facies (Qiongzhusi Formation and Canglangpu Formation). At this stage, thick shale and clastic rock deposited in Sichuan basin. At the end of the Early Cambrian, a carbonate platform developed in upper Yangtze platform, and Sichuan basin was located in restricted platform (Longwangmiao Formation). In the Middle Cambrian, tidal flat and restricted platform developed in Sichuan basin (Douposi Formation), because of continuous regression. During the Late Cambrian, Sichuan basin was located in carbonate platform again (Xixiangchi Formation). There are three types of sedimentary system in the Cambrian of Sichuan basin: clastic sedimentary system, clastics-carbonate mixed sedimentary system and carbonate sedimentary system. Vertically, the basin shows the evolutionary character of clastic-carbonate sedimentary systems. The three sedimentary systems correspond to three “transgression-regression” cycles of the Cambrian. The transgression in the initial period of the Early Cambrian led to the formation of clastic sedimentary system in the Qiongzhusi Formation of Lower Cambrian. The transgression in the later period of the Early Cambrian led to the formation of clastic-carbonate mixed sedimentary system in the Middle-Lower Cambrian. The transgression in the initial period of the Late Cambrian led to the formation of carbonate sedimentary system in the Xixiangchi Formation of Upper Cambrian. With the end of Late Sinian continental rifting ended, Sichuan basin entered a stable evolutionary stage of the craton basin, while the paleo-land developed in the north and southwest. In Qiongzhusi-Canglangpu period, the basin developed onshore-shelf sedimentary facies from west to east; In Longwangmiao-Xixiangchi period, the basin developed tidal flat-platform-slope sedimentary facies from west to east.

Shale gas potential of the lower Silurian hot shales in southern Iran and the Arabian Plate: Characterization of organic geochemistry

A significant phase of global warming appeared during the Llandovery and productive Silurian hot shale was preserved all over the world. The lower Silurian shale is the main effective source rock for most of the Paleozoic hydrocarbon in Iran and the Arabian platform. Silurian hot shales have become prospective resources for new energy such as shale gas. The regional distribution and shale gas potential of the lower Silurian hot shale in southern Iran and the Arabian plate are determined using outcrops and exploration well samples data from previous studies. The studied area has a high organic content (on average more than 2%), maximum burial depth is 5300 m, shale thickness of 30–200 m, organic matter maturities (most comparable), clay minerals content ranging from 20% to 57%, quartz content ranges from 20% to 49%, feldspar content ranges from 10% to 15% and calcite content ranges from 1.48% to 5% which all favor shale gas generation and accumulation. We concluded that southern Iran and east-central Saudi Arabia are two of the most sustainable and favorable locations for shale gas exploration and production for lower Silurian hot shale after assessing all of the key characteristics.

Evaluation of the Accumulation Conditions and Favorable Areas of Shale Gas in the Upper Palaeozoic Marine-Continental Transitional Facies in the Daning-Jixian Area, Ordos Basin

This study focuses on the organic-rich mud shale in the Upper Palaeozoic transitional facies in the southeastern margin of the Ordos Basin. It systematically analyzes the shale gas accumulation conditions of the organic-rich mud shale in the Lower Permian Shanxi-Taiyuan Formation, including the thickness, distribution, organic matter type and content, thermal maturity, reservoir space, gas-bearing property, and rock brittleness. The results show that the thick dark mud shale contains a high organic matter content, is a suitable kerogen type for gas generation, and exhibits moderate thermal evolution, providing excellent conditions for hydrocarbon accumulation. Residual primary pores formed by shale compaction, secondary pores formed by organic matter hydrocarbon generation, clay mineral transformation and dissolution, and fractures provide suitable reservoir spaces for shale gas. The shale in the study area has a higher gas content than the shale strata in the marine basins of the United States. In addition, the content of brittle minerals such as quartz is higher, and Poisson’s ratio is lower, facilitating the subsequent transformation. The accumulation conditions indicate the high potential of the study area for shale gas exploration and development. The geological analogy method is used to compare the study area with five major shale gas basins in the United States. The results indicate that the shale gas resources of the Shanxi-Taiyuan Formation in the study area are in the range of 2800– 3200 × 10 8 m3. The primary controlling factors affecting shale gas reservoirs in this area are the abundance of organic matter, thermal maturity, shale thickness, and quartz content. Favorable areas are predicted based on these factors.

Stratigraphy and origin of Upper Cretaceous wedge-top and proximal foredeep deposits in the Mexican foreland basin, east-central Mexico

Upper Campanian (?) to lower Maastrichtian strata exposed in the Mexican fold and thrust belt east and south of Cárdenas, San Luis Potosí (SLP), record an abrupt transition from marine foredeep sedimentation to continental deposition on the frontal part of the orogenic wedge. Shale and subordinate fine-grained sandstone of the middle Campanian–Maastrichtian Méndez Formation east of Cárdenas represent medial and distal foredeep deposits of the Mexican foreland basin. Correlative proximal deposits of the Cárdenas Formation near the village of Cárdenas consist of thick shale and fine-grained sandstone turbidite beds intercalated with thickly-bedded breccias composed of transported rudists, and other pelecypods and corals in a mudstone matrix. The fossiliferous beds are interpreted as bioclastic debris-flow deposits that accumulated in deep water of the proximal foredeep and/or wedge-top depozone. The overlying Tabaco Formation consists of conglomerate and lenticular sandstone beds as much 1.6 m thick interbedded with red shale and bioturbated, cross-stratified sandstone beds, representing deposition in fluvial channels and floodplains in a rapidly uplifted wedge-top basin.Maximum depositional age (MDA) values calculated from young grains (n = 3 grains) of the Upper Cretaceous strata yield somewhat older ages than those derived from published and new biostratigraphy data. A sandstone sample from the Méndez Formation yielded an MDA of 73.3 ± 7.5 Ma, imprecise but consistent with a middle to late Campanian biostratigraphic age reported here from an associated Méndez shale sample. Two sandstone samples from the middle part of the Cardenas Formation yielded MDAs ranging from 73.4 ± 1.5 Ma to 72.9 ± 3.7 Ma, slightly older than a reported early Maastrichtian biostratigraphic age based on ammonites and corals, but consistent with a new age range, based on nannofossils, of middle Campanian-early Maastrichtian for strata consisting of mixed Méndez and Cárdenas lithofacies. Five sandstones of the Tabaco Formation yielded an MDA range of 73.9–67.9 Ma (Campanian–Maastrichtian), but with substantial 2σ errors of 3–5 my.Sandstone petrography and detrital zircon U -Pb geochronology indicate that sediment sources were Upper Cretaceous sedimentary strata exposed in the Mesa Central and the frontal part of the Mexican fold-and-thrust belt. Cárdenas and Tabaco sandstones contain dominant extrabasinal carbonate lithic grains, reflecting progressive uplift and significant erosion of Lower Cretaceous platformal carbonate and pre-Campanian foreland basin strata, coupled with a decrease in the magmatic activity of the Mexican Cordilleran arc. We propose that the Cárdenas Formation, formerly interpreted as a carbonate platform deposit on the basis of its abundant coral content, was deposited by sediment-gravity flows sourced from nearby reefal facies that likely developed on growing folds. Deposition of the Cárdenas Formation took place in the proximal foredeep or a wedge-top basin on the frontal part of the fold-thrust belt. Coeval deposition of the Méndez Formation took place in the proximal foredeep. Continental deposits of the Tabaco Formation, which overlies the Cárdenas Formation, record an abrupt shift to continental deposition concomitant with a transition to dominantly thrust-belt sediment sources. The transition in facies and sandstone composition record shoaling of the wedge-top basin during emergence of a frontal thrust sheet. Upper Campanian-lower Maastrichtian strata therefore provide important insight on temporal and topographic evolution of the Mexican orogen in east-central Mexico.

Cyclic variations in paleoenvironment and organic matter accumulation of the Upper Ordovician–Lower Silurian black shale in the Middle Yangtze Region, South China: Implications for tectonic setting, paleoclimate, and sea-level change

During the Ordovician–Silurian transition, the Yangtze Block in South China experienced intense tectonic movements and climate change and was covered by the widely distributed black shales of the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation, which recorded key information about these major geological events. By geochemical and petrological analyses of three profiles located in the Middle Yangtze Region, at least four long-term sedimentary cycles can be identified in the Upper Ordovician–Lower Silurian black shale. These cycles are mainly controlled by paleoclimate changes and tectonic activity. The Late Ordovician tectonic subsidence related to the Kwangsian Orogeny promoted a gradual sea-level rise and the deposition of the Wufeng black shale in the Middle Yangtze Region, while a significant sea-level fall related to the Hirnantian intensifying glaciation terminated this process. Subsequently, post-Hirnantian warming climate and glacier ablation triggered a significant sea-level rise, reduced the water restriction, increased the productivity, and intensified the anoxic environment, promoting the deposition of black shale in the second sedimentary cycle. However, after the short period of climate warming, global climate cooling occurred again with a regional tectonic uplift in the study area. This led to a gradual sea-level fall, reduced anoxic environment, and increased water restriction during the Rhuddanian, as well as the deposition of black shale with a decreased amount of organic matter. Moreover, intensified glaciation occurred during the Rhuddanian–Aeronian transition significantly accelerated the falling speed of the relative sea level, resulting in a stratigraphic gap and a small thickness of the Silurian black shale in the Middle Yangtze Region. Afterward, the study area experienced a significant climate warming event during the Early Aeronian, which led to a large-scale glacier ablation and a short period of sea-level rise. This promoted the deposition of the Aeronian black shale in the third sedimentary cycle. Nevertheless, the intensified weathering condition related to a continuously warming climate and tectonic uplift led to sufficient supply of terrigenous deposits, sustained sea-level fall, and finally terminated the development of Ordovician–Silurian black shale in the Yangtze region. Thus, these cyclic variations of the black shale not only recorded the shift of the Ordovician–Silurian tectonic movement (from Ordovician subsidence to Silurian uplift) in the Middle Yangtze area and the Hirnantian glaciation, but also provide strong evidence for the global intensified glaciation during the Rhuddanian–Aeronian transition and the subsequent climate-warming event. In addition, this study also provides new perspectives for the understanding of global sea-level change during the Ordovician–Silurian transition.

Correction of gas adsorption capacity in quartz nanoslit and its application in recovering shale gas resources by CO2 injection: A molecular simulation

Accurate molecular simulations of the competitive adsorption behaviors of CH4 and CO2 in shale reservoirs are crucial for understanding the fundamental mechanisms of fluids storage and recovery under actual burial depth. In this work, the shale thickness of 79.82 nm (143 layers) at each side of quartz wall in theoretical model was advanced for gas adsorption capacity correction. In this case, the adsorption mechanism of shale gas and its recovery mechanism by CO2 injection were systematically pursued at varied burial depth, pore size, moisture content, and gas mole fraction by Grand Canonical Monte Carlo (GCMC) and molecular dynamics (MD) simulations. Adsorbed and free capacities of CH4 gas were determined individually. Gas loss rate and recovery efficiency were put forward to evaluate the recovery of shale gas by H2O and CO2 molecules. The obtained results show that the enrichment region of CH4 is ∼2400 m, which is predicted to be the economically feasible mining depth of CH4. Shallow burial depth (600–800 m) should be favorable for the sequestration of CO2. The results obtained are expected to provide significant theoretical guidance for the reliable evaluation and economic exploitation of shale gas as well as the sequestration of CO2.

Deep Directional Electromagnetic Technique Improves Well-Drilling Efficiency

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202265, “Leap of Faith From Conventional to EM Look-Ahead: A Game-Changing Technology To Improve Well Efficiency,” by Muhamad Yanuar Mahardi, Hendarsyah Hendarsyah, and Kharisma Endarmoyo, PT Pertamina, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. The structure in the Matindok block in Central Sulawesi operated by Pertamina has proven producible gas reserves in the Minahaki formation. One of the main challenges in this area is the low resolution of seismic data, leading to a high depth uncertainty. The complete paper describes a technology developed to meet these challenges with the capability to map and detect lithology changes ahead of the bit in real time. Geological Background A first exploration well, PEP-001, was drilled in 2018. The structure has a Miocene carbonate buildup play, and the target reservoir is the M pinnacle carbonate reef. The PEP-001 well was planned to set the 9⅝-in. casing point above the top of the M formation. Offset wells did not show any clear markers in the thick shale above the M formation that could have been used for log correlation. In previously drilled offset wells, correlation was performed convention-ally by examination of cutting samples and on drilling breaks. However, when Well PEP-001 was drilled, no apparent drilling break was observed. By the time cuttings reached the surface, the bit had drilled into 20 m of the M formation. Because the casing covered most of the upper carbonate formation, openhole logging and well-testing data were not acquired to delineate the target formation optimally. The second exploration well, PEP-002, was planned with an objective of setting 9⅝-in. casing approximately 5 m above the top of M to acquire full-interval coverage of coring, openhole wireline logging, and well testing. This information was critical for optimal reservoir delineation to allow for accurate reserves calculation and future development. Conventional correlation methods have proven insufficient for casing point placement. The presence of limestone stringers in offset wells within proximity of the top of M presented an additional challenge. The stringers could have been misinterpreted as the main carbonate body, if interpretation were based solely on cutting samples. Real-Time Electromagnetic (EM) Look-Ahead Technology

Quantitative assessment of the sweet spot in marine shale oil and gas based on geology, engineering, and economics: A case study from the Eagle Ford Shale, USA

Shale oil and gas have become important areas of petroleum exploration and development. Successful shale oil and gas exploration depends on the accurate evaluation of sweet spots, which are the commercial targets. This paper proposes a comprehensive new method for sweet spot evaluation based on average estimated ultimate recovery in barrels of oil equivalent (EUR_BOE) in conjunction with key geological factors, engineering and technical conditions, and economic and technical indicators. Research results from 72 systematically cored wells, 991 sets of core analyses, and production data from 1317 horizontal wells in the lower Eagle Ford Shale (EFS) of the U.S. Gulf Basin show that marine shale oil and gas sweet spots depend primarily on four key factors: oil and gas resources, oil and gas storage capacity, fluidity, and fracability. These conclusions are based on quantitative evaluation models relating to EUR_BOE and key geological parameters. Model outcomes are controlled by inputs for total organic carbon (TOC), vitrinite reflectance (%Ro), original formation and hydrostatic pressure difference (ΔPf–h) or formation pressure gradient (Pindex), effective shale thickness (Heshale), clay volume content (Vclay), fracture porosity (Φf)and other geological parameters pertaining to EUR_BOE. Shale oil and gas sweet spots in non-fractured zones must satisfy certain conditions including TOC ≥2.3 wt%, Ro ≥ 0.9%, Heshale ≥ 15 m, Vclay ≤ 25 vol%, and ΔPf–h between ∼3 and 35 MPa or Pindex between ∼1.15 and 1.85 MPa/100 m. Defining shale oil and gas sweet spots in fractured zones is more complex, because developing fractures and the application of advanced engineering technology will increase EUR_BOE; sweet spots are impacted by sealing conditions, fracture and fault development, and technical engineering conditions. The proposed method for evaluating shale oil and gas sweet spots is validated through the determination of sweet spots in the lower EFS, and provides a basis for the evaluation of shale oil and gas sweet spots in similar marine deposits.

Sedimentary tectonic pattern of Wufeng and Longmaxi Formations in the northern margin of Sichuan Basin, South China

ABSTRACT Organic-rich black shales in the Sichuan Basin from the Upper Ordovician and Lower Silurian are considered excellent source rocks and unconventional reservoirs of hydrocarbons in South China. The Wufeng and Longmaxi Formations in the Micangshan – Dabashan areas of the northern margin of Sichuan Basin were taken as the research objects. The purpose of this study is to reconstruct the sedimentary tectonic pattern of the Wufeng and Longmaxi Formations in the study area. First, the stratigraphic framework correlation and sedimentary facies analysis of Wufeng and Longmaxi Formations in the study area were carried out. Then, Mo/TOC and Al-Co[EF]×Mn[EF] geochemical indicators were used to identify the degree of water restricted during the deposition period. It was found that the thickness of black shale was relatively small near the uplift area. However, far away from the uplift area, from west to east, the black shale thickened and the TOC content increased gradually, which were controlled by the upwelling of continental margin and intracontinental depression. The results show that: (1) At the front edge of Micangshan, during the deposition period of Wufeng Formation, Fucheng and Qiaoting profiles were located in the intersection area of upwelling formed by two kinds of monsoon, which led to the long-term influence of upwelling in this area. The sedimentation period of Longmaxi Formation was mainly affected by ‘Xixiang Rise’, which led to the uplift of Wangcang and Nanjiang areas into islands. (2) At the front edge of Dabashan and Western Hubei – Eastern Chongqing areas, the Wufeng Formation presented a tectonic pattern of alternating uplift and depression. Due to the continuous compression of the Cathaysian Block from southeast to northwest, the Shizhu – Wuxi areas continued to subside during the deposition period of Longmaxi Formation, and the black shale was quite thick.