Marine Shale Formations Research Articles

Quantifying the Pore Heterogeneity of Alkaline Lake Shale during Hydrous Pyrolysis by Using the Multifractal Method

Distinguishing itself from marine shale formations, alkaline lake shale, as a significant hydrocarbon source rock and petroleum reservoir, exhibits distinct multifractal characteristics and evolutionary patterns. This study employs a combination of hydrous pyrolysis experimentation, nitrogen adsorption analysis, and multifractal theory to investigate the factors influencing pore heterogeneity and multifractal dimension during the maturation process of shale with abundant rich alkaline minerals. Utilizing partial least squares (PLS) analysis, a comparative examination is conducted, elucidating the disparate influence of mineralogical composition on their respective multifractal dimensions. The findings reveal a dynamic evolution of pore characteristics throughout the maturation process of alkaline lake shale, delineated into three distinct stages. Initially, in Stage 1 (200 °C to 300 °C), both ΔD and H demonstrate an incremental trend, rising from 1.2699 to 1.3 and from 0.8615 to 0.8636, respectively. Subsequently, in Stages 2 and 3, fluctuations are observed in the values of ΔD and D, while the H value undergoes a pronounced decline to 0.85. Additionally, the parameter D1 exhibits a diminishing trajectory across all stages, decreasing from 0.859 to 0.829, indicative of evolving pore structure characteristics throughout the maturation process. The distinct alkaline environment and mineral composition of alkaline lake shale engender disparate diagenetic effects during its maturation process compared with other shale varieties. Consequently, this disparity results in contrasting evolutionary trajectories in pore heterogeneity and multifractal characteristics. Specifically, multifractal characteristics of alkaline lake shale are primarily influenced by quartz, potassium feldspar, clay minerals, and alkaline minerals.

Comparative Study on the Primary Control Factors of Nanopores in Transitional and Deep Marine Shale in the Southeastern Sichuan Basin, China

The deep marine shale from the Silurian Longmaxi Formation and transitional shale from the Permian Longtan Formation in the Sichuan Basin are two promising targets for shale gas exploration in China. In this study, nanopore characteristics for deep marine and transitional shale samples collected from the same well in the southeastern Sichuan Basin are investigated and compared via field emission scanning electron microscopy imaging, low-pressure gas adsorption, total organic carbon measurement, and X-ray diffraction. Results show that clay-related pores are well developed, pores within organic matter (OM) are rare, and shrinkage cracks along the OM-edge are widely prevalent in transitional shales. The deep marine shale is rich in bubble-like OM pores. The transitional shale has a larger pore volume but a lower specific surface area compared to the deep marine shale. The nanoporosity of the transitional shales is primarily controlled by clay and OM content. In deep marine shale, OM is the primary contributor to nanoporosity. Higher nanoporosity in the deep marine shales than in the middle-shallow ones was observed in this study. This occurrence is attributed to the high fluid pressure and the resulting superior preservation conditions for nanopores in deep marine shale formations.

E&P Notes (November 2022)

E&P Notes (November 2022)

Geomechanical Modeling and Inversion Analysis of the in-situ Stress Field in Deep Marine Shale Formations: A Case Study of the Longmaxi Formation, Dingshan Area, China

Based on the comprehensive analysis of wellbore characteristics in a deep shale gas field, the in-situ stress state of the shale reservoir was assessed in this study for the Longmaxi formation in the Dingshan area, Southwestern China. The data obtained from hydraulic fracturing, drilling-induced fractures, and in-situ core testing were used to determine the magnitude and direction of the maximum principal horizontal stress in five wells. Besides, hydraulic fracturing and cross-multipole array acoustic logging (XMAC) were employed to determine the vertical variation of the in-situ stress. Based on the logging interpretation and mechanical test results, the spatial distribution of rock mechanical parameters in the Dingshan area was assessed by the amplitude variation versus offset (AVO) seismic inversion. A 3D heterogeneous mechanical inversion model was realized via the ANSYS and CATIA3D finite element software packages, providing the area in-situ stress field simulation. The depth, fault strike, and position change effects on the main stress, horizontal stress difference, and horizontal stress difference coefficient were numerically simulated. The results show that the maximum principal stress azimuth was mainly concentrated in the NE20°-NE80° sector. Moreover, the development zone of natural fractures was related to the area with the highest principal stress differences. The maximum principal stress variation in the study area was mainly in the compressive range from −135 to −45 MPa, gradually increasing from east to west and south to north. The stress type mainly depended on the depth, fault strike, and rock mechanical parameters, while the stress difference and stress difference coefficient near the fault structure were relatively small. This study’s findings are considered instrumental in improving the borehole stability, determining the casing setting point, and optimizing the well location in deep shale reservoirs with similar geological conditions.

Statistical analysis and significance of pyrite in the Wufeng-Lower Longmaxi Shale Formation in South China

Pyrite from outcrops of Late Ordovician–Early Silurian marine shales of the Sichuan Basin was studied in the laboratory setting. We characterized various occurrences of pyrite using optical microscopy, reflected light microscopy, X-ray analysis, scanning electron microscopy, and energy-dispersive analysis, and image analysis to aid visual estimates of pyrite in polished sections. We observed two classes and four subclasses of pyrite in this marine shale depositional environment. A total of 2964 pyrite framboids and 16,393 pyrite monocrystal particles were measured, with an average particle size value from 2.57 to 6.24 μm in framboidal pyrite and from 0.32 to 0.61 μm in component monocrystals. Over 88% of framboidal pyrite particle size ranges from 1.5 to 9 μm, and the diameter between 0.2 and 0.8 μm is greater than 89% of total pyrite monocrystal particles. The cubic form of pyrite has particle sizes that range from 2.56 to 101.93 μm, more than 83% ranging from 5 to 30 μm. Image analysis of pyrite particle reveals dimensions between 1.0 and 7.5 μm and shape factors from 0.9 to 1.0 (nearly round), indicating that the primary pyrite type in marine shale formation is framboidal pyrite. The framboidal pyrite has important geological significance for marine shale formations. Size analysis, organic matter content, and stratigraphic distribution of framboidal pyrite reveal that the average particle size of framboidal pyrite varies according to deposition in either a dysoxic or a euxinic sedimentary environment. The Fe and S atomic content in framboidal pyrite is relatively low and correlates with high C atomic content, which suggests a close relationship between framboidal pyrite and organic matter. We identified six pore types in this study. Pores are developed in organic matter that occurs between framboidal monocrystals, as well as in organic matter that surrounds framboidal pyrite. Despite their small size, organic porosity remains conducive to the natural gas adsorption, and porosity associated with pyrite may also contain methane in the subsurface.

Fractal characterization of pore structure and its influence on salt ion diffusion behavior in marine shale reservoirs

Hydraulic fracturing becomes a significant way to develop fossil hydrogen energy from marine shale. Some marine shale formations have a higher salt ion concentration in flowback fluid, about which the mechanism is still unclear. In this study, both the fractal characterization of pore structure and its influence on salt ion diffusion was researched. The fractal dimension D1 can reflect the roughness of pore surface, and the fractal dimension D2 can reflect the complexity of pore structure. The fractal dimension D1 of Sichuan Niutitang Formation is only 2.0069 and the ones of other shale samples are between 2.5291 and 2.6341, which means that the pore surface of Sichuan Niutitang Formation is far smoother than the ones of other samples. The fractal dimension D2 ranges from 2.7396 to 2.9546, which indicates that all samples have complex pore structure. The salt ion diffusion rate is mainly controlled by specific surface area, median pore-throat radius and clay content. A higher specific surface area provides more surface for the interaction between liquid and matrix, and lots of salt ion was released into imbibed liquid. A larger median pore-throat radius benefits to salt ion diffusing out of sample, thus a higher salt ion diffusion rate appears. The liquid can cause the clay-swelling which has the potential to reduce the salt ion diffusion channel, thus the higher the clay content, the lower the salt ion diffusion rate. Our research is conducive to understanding the fractal characterization of marine shale and its impact on high salt ion concentration in flowback fluid.

Impact of CO2 Induced Mineral Dissolution and Precipitation on Porosity and Permeability of Lower Tuscaloosa and Marine Shale Formations (Mississippi, USA): A Numerical Study

Impact of CO2 Induced Mineral Dissolution and Precipitation on Porosity and Permeability of Lower Tuscaloosa and Marine Shale Formations (Mississippi, USA): A Numerical Study

Lower limit of thermal maturity for the carbonization of organic matter in marine shale and its exploration risk

Abstract Based on the drilling data of the Silurian Longmaxi Formation in the Sichuan Basin and periphery, SW China, the Ro lower limits and essential features of the carbonization of organic matter in over-high maturity marine shale were examined using laser Raman, electrical and physical property characterization techniques. Three preliminary conclusions are drawn: (1) The lower limit of Ro for the carbonization of Type I-II1 organic matter in marine shale is 3.5%; when the Ro is less than 3.4%, carbonization of organic matter won't happen in general; when the Ro ranges from 3.4% to 3.5%, non-carbonization and weak carbonization of organic matter may coexist; when the Ro is higher than 3.5%, the carbonization of organic matter is highly likely to take place. (2) Organic-rich shale entering carbonization phase have three basic characteristics: log resistivity curve showing a general “slender neck” with low-ultralow resistance response, Raman spectra showing a higher graphite peak, and poor physical property (with matrix porosity of only less than 1/2 of the normal level). (3) The quality damage of shale reservoir caused by the carbonization of organic matter is almost fatal, which primarily manifests in depletion of hydrocarbon generation capacity, reduction or disappearance of organic pores and intercrystalline pores of clay minerals, and drop of adsorption capacity to natural gas. Therefore, the lower limit of Ro for the carbonization of Type I-II1 organic matter should be regarded as the theoretically impassable red line of shale gas exploration in the ancient marine shale formations. The organic-rich shale with low-ultralow resistance should be evaluated effectively in area selection to exclude the high risk areas caused by the carbonization of organic matter. The target organic-rich shale layers with low-ultralow resistance drilled during exploration and development should be evaluated on carbonization level of organic matter, and the deployment plan should be adjusted according to the evaluation results in time.

Pore characterization and its impact on methane adsorption capacity for organic-rich marine shales

Shale matrix pore structure controls the gas storage mechanism and gas transport behaviors. We employed various techniques to characterize the complex pore structures of 12 shale samples collected from two marine shale formations in upper Yangtze area (UYA) in China. The characterization techniques include field emission scanning electron microscopy (FE-SEM), high-pressure mercury intrusion porosimetry (MIP), and low-pressure N2/CO2 adsorption. The excess methane adsorption capacity was measured for each sample and the results were modeled using Langmuir model. Based on the FE-SEM image analyses, micro- and meso-pores within organic matter and inter-particle pores between or within clay minerals are the most commonly developed in these shale samples. Both uni- and multi-modal pore size distributions (PSDs) were observed, and a significant portion of pores are in the pore size range between 3 and 100nm. It was also found that the micropore (<2nm) is the major contributor to the overall specific surface area (SSA), whereas most of the pore volume is occupied by mesopores (2–50nm). Two different fractal dimensions, pore surface fractal dimension (D1) and spatial geometry fractal dimension (D2), were estimated from low pressure N2 isotherms, with D1 ranging between 2.469 and 2.682, and D2 ranging between 2.576 and 2.863, indicating that the surface and volume of pore structure are heterogeneous. Samples with higher D1 can provide more adsorption sites for methane and tends to have relatively high adsorption capacity, whereas shales with higher D2 do not influence the gas adsorption and storage capacities. Methane adsorption capacity increases with the increase of both micropore volume and micropore surface area, and this confirms that microporosity is the governing factor on methane adsorption capacity and storage.

Natural gas potential of Neoproterozoic and lower Palaeozoic marine shales in the Upper Yangtze Platform, South China: geological and organic geochemical characterization

In this article, we describe the geological features of the Ediacaran (upper Sinian), lower Cambrian and lower Silurian shale intervals in the Upper Yangtze Platform, South China, and report on the gas potential of 53 samples from these major marine shale formations. Reflected light microscopy, total organic carbon (TOC) measurement, Rock-Eval, carbon isotope ratio analysis, thermovaporization gas chromatography (Tvap-GC), and open pyrolysis gas chromatography (open py-GC) were used to characterize the organic matter. Measured TOC in this research is normally >2% and averages 5%. TOC contents are roughly positively correlated with increasing geological age, i.e. lower Silurian shales exhibit generally lower TOC contents than lower Cambrian shales, which in turn commonly have lower TOC contents than Ediacaran shales. Kerogen has evolved to the metagenesis stage, which was demonstrated by the abundant pyrobitumen on microphotographs, the high calculated vitrinite reflectance (Ro = 3%) via bitumen reflectance (Rb), as well as δ13 C of gas (methane) inclusions. Pyrolysates from Tvap-GC and open py-GC are quantitatively low and only light hydrocarbons were detected. The lower Silurian shale generally exhibits higher generation of hydrocarbon than the lower Cambrian and Ediacaran shale. Cooles’ method and Claypool’s equations were used to reconstruct the original TOC and Rock-Eval parameters of these overmature samples. Excellent original hydrocarbon generation was revealed in that the original TOC (TOCo) is between 5% and 23%, and original S1+S2 (S1o+S2o) is ranging from 29 to 215 mg HC/g rock.

Shale gas potential of the major marine shale formations in the Upper Yangtze Platform, South China, Part II: Methane sorption capacity

The marine black shale formations on the Upper Yangtze Platform (UYP), South China are exploration targets for shale gas. Here, we report on the methane sorption capacity of thermally overmature samples from the Lower Silurian and Lower Cambrian black shale intervals in the UYP (UYP-samples). Two immature shale samples from the Middle Cambrian formation in the Georgina Basin, North Australia (AU samples) were also tested to investigate the effect of thermal maturity on sorption isotherms. Excess sorption isotherms were performed over a pressure range of 0–25MPa at 46°C. The effects of TOC content, thermal maturity, clay minerals, moisture content, pore properties, particle size, temperature, and pressure on methane sorption capacity were analysed. In addition, thermovaporisation gas chromatography (Tvap-GC) was used to measure the residual gas that is stored in the samples under atmospheric pressure and temperature conditions.The results indicate that the maximum methane excess sorption of the Lower Silurian samples is between 0.045 and 0.064mmol/g rock and that of Lower Cambrian samples is between 0.036 and 0.210mmol/g rock. The Langmuir sorption capacity of the Lower Silurian samples ranges from 0.096 to 0.115mmol/g rock, whereas that of the Lower Cambrian shale ranges from 0.077 to 0.310mmol/g rock. These results are close to the sorption capacities of the Barnett (U.S.), Devonian–Mississippian (Western Canada), and Alum (Southern Scandinavia) shale samples. The shape of the sorption isotherms and methane sorption capacity vary from sample to sample. Under the measured pressure range, the isotherms of the selected immature AU Cambrian samples increase monotonously with pressure, whereas the overmature UYP samples exhibit maxima. The methane sorption capacity of the measured samples positively correlates with TOC content and exhibits a distinct linear relation. The TOC-normalised sorption capacity shows a positive correlation with thermal maturity; however, the corresponding pressure of maximum excess sorption and Langmuir pressure decrease substantially with increasing thermal maturity. The clay minerals show a positive effect on the TOC-normalised sorption capacity. The sorption capacity of clay minerals, however, should have been reduced by the moisture content. The two Lower Cambrian samples that have similar maturities were measured for porosity and pore-size distribution. The sample with a high TOC content shows a high total cumulative pore volume, surface area, total porosity and thus a higher sorption capacity than the sample with less TOC. In addition, larger-sized particles show slightly less sorption capacity than smaller-sized particles. The Tvap-GC results show that the residual gas content of core samples is evidently higher than that of the outcrop samples, which implies a remarkably negative effect of the weathering process.

Geological Conditions and Prospect Forecast of Shale Gas Formation in Qiangtang Basin, Qinghai‐Tibet Plateau

Abstract:The presence of shale gas has been confirmed in almost every marine shale distribution area in North America. Formation conditions of shale gas in China are the most favorable for marine, organic‐rich shale as well. But there has been little research focusing on shale gas in Qiangtang Basin, Qinghai‐Tibet Plateau, where a lot of Mesozoic marine shale formations developed. Based on the survey results of petroleum geology and comprehensive test analysis data for Qinghai‐Tibet Plateau, for the first time, this paper discusses characteristics of sedimentary development, thickness distribution, geochemistry, reservoir and burial depth of organic‐rich shale, and geological conditions for shale gas formation in Qiangtang Basin. There are four sets of marine shale strata in Qiangtang Basin including Upper Triassic Xiaochaka Formation (T3x), Middle Jurassic Buqu Formation (J2b), Xiali Formation (J2x) and Upper Jurassic Suowa Formation (J3s), the sedimentary types of which are mainly bathyal‐basin facies, open platform‐platform margin slope facies, lagoon and tidal‐flat facies, as well as delta facies. By comparing it with the indicators of gas shale in the main U.S. basins, it was found that the four marine shale formations in Qiangtang Basin constitute a multi‐layer distribution of organic‐rich shale, featuring a high degree of thickness and low abundance of organic matter, high thermal evolution maturity, many kinds of brittle minerals, an equivalent content of quartz and clay minerals, a high content of feldspar and low porosity, which provide basic conditions for an accumulation of shale gas resources. Xiaochaka Formation shale is widely distributed, with big thickness and the best gas generating indicators. It is the main gas source layer. Xiali Formation shale is of intermediate thickness and coverage area, with relatively good gas generating indicators and moderate gas formation potential. Buqu Formation shale and Suowa Formation shale are of relatively large thickness, and covering a small area, with poor gas generating indicators, and limited gas formation potential. The shale gas geological resources and technically recoverable resources were estimated by using geologic analogy method, and the prospective areas and potentially favorable areas for Mesozoic marine shale gas in Qiangtang Basin are forecast and analyzed. It is relatively favorable in a tectonic setting and indication of oil and gas, shale maturity, sedimentary thickness and gypsum‐salt beds, and in terms of mineral association for shale gas accumulation. But the challenge lies in overcoming the harsh natural conditions which contributes to great difficulties in ground engineering and exploration, and high exploration costs.

Shale Gas Potential of the Major Marine Shale Formations in the Upper Yangtze Platform, South China, Part III: Mineralogical, Lithofacial, Petrophysical, and Rock Mechanical Properties

The marine black shale formations on the Upper Yangtze Platform, South China, are currently exploration targets for shale gas. Here, we report on the mineralogy, lithofacies, petrophysics, and rock mechanics of samples collected from the Ediacaran (Upper Sinian), Lower Cambrian, and Lower Silurian black shale intervals. All three formations are composed of high proportion of quartz, low content of clay, and rare or nonexistent content of carbonates. The Ediacaran and Lower Cambrian shales deposited in restricted deep water marine platform to marine basin environments are characterized by a higher quartz content and lower clay content than the Lower Silurian shales that were deposited in a more restricted marine basin environment. The carbonate content varies from 0 to over 50%, with the higher values measured in the Lower Silurian samples. These stratigraphic units were formed during bottom water anoxic conditions; therefore, they were rarely influenced by bioturbation. Lithologically, laminated and nonlaminated siliceous mudstones predominate, with minor contributions of other lithotypes. Pores generally have diameters in the nanometer (nm) to micrometer (μm) range, and numerous pores occur in organic matter. Most of the measured samples have porosities less than 4%, although a few samples show porosity in excess of 10%. Pores with radii less than 50 nm contribute significantly to total pore volume and total porosity. Permeability is extremely low, and helium permeability coefficients (Klinkenberg corrected permeability coefficient) are less than 20.2 nD (nano-Darcy, ∼2 × 10–20 m2). The rock mechanical properties of the samples are characterized by high brittle behavior, which coincides with their high compressive and tensile strengths and elastic properties. The Lower Cambrian shale is generally more brittle than the Lower Silurian shales, which possess a relatively higher content of clay minerals. The rock mechanical properties of the measured samples, however, depend on the overall mineral compositions and physical properties.

Late Cretaceous Deltas, Rocky Mountain Region: ABSTRACT

During the Late Cretaceous, a basin of deposition covered the western interior of the North American continent, extending from the present Gulf of Mexico to the Arctic. Large quantities of detrital sediment were transported from a source area along the western margin of the basin and deposited in coastal plain, shoreline, and marine environments. Rivers carrying the sediment load formed three large delta complexes: one in central Montana; a second in central Wyoming; and, a third in northern Colorado and southwest Wyoming. These three deltaic centers formed dispersal points from which sediment was carried and distributed within the basin by marine processes. Of the three delta complexes, the northern Colorado-southwest Wyoming delta contains the greatest volume of sedimen , representing 2 to 3 times the volume of each delta to the north. Deltas are defined by establishing time-stratigraphic units in the marine shale formations, either by faunal or physical criteria, and by tracing these units into the shoreline sandstone and coastal plain deposits. Lithofacies maps, isopachous maps, and restored sections are prepared for each time-stratigraphic unit. The recognition of a delta is based on two or more of the following criteria: 1) an arcuate lithofacies pattern of coastal plain strata (nonmarine) protruding into the marine basin; 2) for a designated time-stratigraphic unit, thickest deposits in the general shoreline zone (area of topset and foreset strata) associated with this lithofacies pattern; 3) a complex intertonguing of marine (foreset and bottomset) and nonmarine (topset) strata; 4) rapidly changing shoreline s ndstone trends from one time-stratigraphic unit to another; 5) abundance of stream deposits over deposits of other environments of coastal plain; 6) biological criteria in marine strata, especially lack of fossils (absence of pelagic calcareous foraminifera); arenaceous benthonic forms tend to dominate; 7) persistence of above criteria in vertical stratigraphic sequence indicating semi-permanency of drainage systems responsible for deltaic deposits. In Upper Cretaceous strata, topset strata are characterized by lenticular sandstone, siltstone, claystone, shale, and coal. Depending on the nature of the river load and the energy of the basin, the foreset strata may be interbedded siltstone and shale, or large sheets of sandstone forming a partial aureole around the nose of the delta. Bottomset strata are shale or interbedded shale and siltstone with minor amounts of sandstone. The Upper Cretaceous (Campanian and Maestrichtian) of southern Wyoming and northern Colorado illustrates deltaic sedimentation and its influence on oil accumulation. Localized deltaic loading caused penecontemporaneous differential deformation of the subsiding basin floor. Incipient structural highs between the more rapidly subsiding delta areas controlled early migration of petroleum in stratigraphic traps. Where subsequent geologic history has favored preservation of these early traps, large petroleum accumulations have been discovered. End_of_Article - Last_Page 363------------

Cretaceous Stratigraphy of Vermilion Area, Alberta, Canada

Cretaceous sediments are penetrated in wells in the Vermilion area of east-central Alberta to depths of 2,000 to 2,500 feet; they rest unconformably either on Devonian dolomites or on a few feet of green shale possibly Jurassic in age. Only one formation, previously unnamed, is Lower Cretaceous in age. It consists of deltaic and associated sediments which are subdivided for the first time into six local members largely on the basis of presence or absence of dark minerals in the sands, microfossils in the marine shale tongue, and occurrence of coal seams. This association of sediments is comparable with the Recent deposits of the Mississippi Delta region. The lower part of the Upper Cretaceous consists of two rather widespread marine shale formations, together about 1,600 feet thick, the older one with white calcareous specks, the younger one without them. These formations are overlain by fresh- and brackish-water sandy sediments, which thin toward the east and are replaced by interfingering marine shales. The interfingering marine shales and near-shore deposits are exposed in the Vermilion area. Their rapid lateral variations make detailed correlations and surface geology difficult.