Shale Content Research Articles

In Situ Gas Content Prediction Method for Shale.

Shale gas is a typical unconventional energy source and recently has received great attention around the world. Unlike conventional natural gas, shale gas mainly exists in two forms: free state and adsorbed state. Therefore, geologists have proposed the concept of gas content. The traditional calculation methods of gas content can be summarized as on-site gas desorption, logging interpretation, isothermal adsorption, and so on. However, all of the methods mentioned above have their shortcomings. In situ gas content is a new concept in the calculation of the gas content. In this paper, the in situ gas content is defined as the gas content obtained by direct measurement of core gas production through experimental or mathematical simulation of original reservoir conditions. In this work, a method to calculate the in situ gas content of shale is provided, which includes two parts: numerical simulation of the coring process and a gas content experiment. Compared with previous gas content prediction methods, this article considers the influence of the temperature field on gas content both in mathematical modeling and experiments. Then, the gas content of the Longmaxi Formation shale in the Sichuan Basin was calculated using both methods as an example. The results show that (1) the numerical model was considered to be reliable by analyzing the effects of coring speed and permeability on the loss of gas; (2) the total gas content predicted by numerical simulation of the coring process and the gas content experiment are approximately equal, with values of 5.08 m3/t and 4.95 m3/t, respectively; (3) the total gas content of the USBM method is only 4.28 m3/t, which is significantly lower than the above methods. In summary, this study provides an in situ gas content prediction method for shale from both mathematical modeling and experiments. The mutual verification of theory and experiment makes this method highly reliable.

Water dispersible clay and micro-structure of soils from coastal plain sands, shale and false-bedded sandstones

Information regarding water-dispersible clays in soils of contrasting textures is needed to evaluate soil qualities that influence susceptibility of soils to slaking in water. Water-dispersible clays (WDCs), plastic limits, and basic properties of soils on Coastal Plain Sands (CPS), Shale (Shale), and False-Bedded Sandstones in southern Nigeria were quantified for use in evaluating management options of some tropical soils. Results revealed that WDCs, micro-aggregate indices, and plastic limits differed significantly amongst the parent materials. At 0–15 cm depth, clay content was 29.7%, 11.2 and 3.8%, for Shale, CPS and False-Bedded sandstones, respectively, indicating significant high clay content in Shale. The highest SOC of 29.8 g kg−1., and very slow saturated hydraulic conductivity (Ksat) of 6.33 cm h−1 were found in Shale. False-Bedded Sandstone had the lowest SOC content of 7.7 g kg−1 and highest Ksat value of 31.10 cm h−1 at 0–15 cm topsoil. Micro-aggregate stability indices measured by aggregated silt+clay (ASC) and clay flocculating index (CFI) were significant in CPS at 0–15 cm, whereas water-dispersible clay (WDC) was significantly higher (p < 0.05) in Shale at 8.32%, compared to very low value of 0.76% in False-Bedded Sandstone. Plastic limit (PL) of 16.5%, was significantly higher (p < 0.05) in Shale, indicating its high sensitivity to mechanical deformation when wet. There was a significant positive correlation between clay content and WDC (r = 0.815, p < 0.01), indicating the positive influence of clay content on WDCs and micro-structural indices, and the tendencies for quick degeneration of the soils.

New Method for Logging Evaluation of Total Organic Carbon Content in Shale Reservoirs Based on Time-Domain Convolutional Neural Network

Total organic carbon (TOC) content is a key indicator for determining the hydrocarbon content of shale. The current model for calculating the TOC content of shale is relatively simplistic, the modeling process is cumbersome, and the parameters involved are influenced by subjective factors, which have certain shortcomings. To address this problem, a time-domain convolutional neural network (TCN) model for predicting total organic carbon content based on logging sequence information was established by starting from logging sequence information, conducting logging parameter sensitivity analysis experiments, prioritizing logging-sensitive parameters as model feature vectors, and constructing a TCN network. Meanwhile, to overcome the problem of an insufficient sample size, a five-fold cross-validation method was used to train the TCN model and obtain the weight matrix with the minimum error, and then a shale reservoir TOC content prediction model based on the TCN model was established. The model was applied to evaluate the TOC logging of the Lianggaoshan Formation in the Sichuan Basin, China, and the predicted results were compared with the traditional ΔlogR model. The results indicate that the TCN model predicts the TOC content more accurately than the traditional model, as demonstrated by laboratory tests. This leads to a better application effect. Additionally, the model fully explores the relationship between the logging curve and the total organic carbon content, resulting in improved accuracy of the shale TOC logging evaluation.

Nitrogen isotopes of released gas from rock crushing and implications to origins of molecular nitrogen in Lower Cambrian overmature shale gas in South China

The origin and formation mechanism of N2-rich Lower Cambrian shale gas remain ambiguous, posing serious exploration risks in the Lower Cambrian shale gas in South China. In this study, high-vacuum-pulsed electromagnetic and helium-filled ball-mill rock-crushing methods were developed to measure the released gas contents, compositions and nitrogen isotopes of N2 in shale-crushed gas from Lower Cambrian organic-rich shales in South China. Key factors in N2 enrichment in shale gas and its origins were investigated. Results showed that mineral compositions and thermal maturity affected the contents and compositions of shale-crushed gas. Carbonate cementation, and feldspar dissolution and reprecipitation, formed isolated pores filled with migrated bitumen and thus generated high gas contents with larger CH4/N2 ratios of shale-crushed gas. The thermal maturation of Lower Cambrian organic-rich shale can be further divided into the early and late stages of overmaturation with a boundary of 3.4–3.5%EqVRo. The contents and CH4/N2 ratios of shale-crushed gas continued to increase at the early stage of overmaturation, and then a rapid decrease at the late stage of overmaturation (>3.4–3.5%EqVRo), reflecting the release of large amounts of N2 by intensified aromatization of organic matter. An empirical equation of TONb = 0.0138 × TOC with R2>0.98 was used to estimate the relative contribution of inorganic nitrogen (TINb) and organic nitrogen (TONb) to the bulk of nitrogen content in the overmature Cambrian shale. The EqVRo-δ15NN2 plot allows identification of N2 derived from thermal decomposition of ammonium-bearing clay minerals or residual kerogen. The N2 generated at the early stage of overmaturation (including at wells LX03, EYY1, SNY1 and W001-4) in Lower Cambrian shale gas is characterized by δ15NN2 values ranging from −2 to +2‰, mainly reflecting thermal deammoniation and decomposition of ammonium-bearing clay minerals. In contrast, the N2 generated at the late stage of overmaturation (DQ outcrop) in Lower Cambrian shale gas is characterized by δ15NN2 values greater than +4‰, indicating thermal cracking of pyridinic nitrogen and pyrrolic nitrogen. The N2 generated from thermal transformation of ammonium-bearing clay minerals and pyridinic nitrogen and pyrrolic nitrogen is the main source of N2-rich shale gas in the Lower Cambrian shale of South China.

Authigenic Carbonate Burial Within the Late Devonian Western Canada Sedimentary Basin and Its Impact on the Global Carbon Cycle

AbstractStable carbon isotope ratios (δ13C values) of marine carbonates are widely used to infer the relative burial rates of organic carbon, a source of oxygen to the ocean‐atmosphere system. This inference, however, is based on the assumption that ocean‐atmospheric carbon is buried either as organic carbon or as marine carbonate minerals. The burial of authigenic carbonate minerals formed within sediments after deposition, with low δ13C values (i.e., similar to organic carbon), has been proposed to explain high δ13C values in marine carbonates without the need for high burial fluxes of organic carbon. To test this hypothesis, we focus on the Late Devonian, a time period with both pervasive ocean anoxia and a severe reduction in shallow‐water carbonate deposition—conditions hypothesized to promote authigenic carbonate formation. We present sedimentological and geochemical data from limestones and black shales of the Wabamun Group, Besa River and Exshaw formations of the Western Canada Sedimentary Basin. These data are compared to inorganic and organic weight percent measurements of North American shales acquired from the USGS National Geochemical Database (N = 4,437). Results show that basinal shale lack authigenic carbonate with low δ13C values and that the mean δ13C value of carbonate in these shales (−0.3‰) do not differ substantially from mean δ13C of carbonates in platform carbonates of a similar age (0.6‰). Furthermore, inorganic carbon content in Late Devonian shales (mean weight percent = 0.55%, N = 54) is lower than average Phanerozoic North American shale (mean of 1.95%, N = 4,055). Lastly, organic carbon‐to‐inorganic carbon ratios (OC:IC) of North American shales are well above 1 (mean = 3.72 for Late Devonian shales (N = 374), 2.25 for shales (N = 3,653) of all other ages). Therefore, even if the burial of fine‐grained siliciclastic formations carrying authigenic carbonates were to increase, the concomitant increase in organic carbon burial would be even larger. Together, data from this study do not provide evidence that the burial of authigenic carbonate would have a significant effect on global carbon isotope mass balance.

Reservoir Characteristics and Exploration Potential Evaluation of Lower Cambrian Niutitang Shale in Northern Guizhou: A Case Study of Well QX1

The Lower Cambrian Niutitang Formation in the Northern Guizhou harbors abundant organic-rich mud shale, constituting the most significant marine shale gas reservoir in Guizhou. In this article, the reservoir characteristics of Lower Cambrian Niutitang Formation in Northern Guizhou are analyzed in terms of lithology, mineralogy, organic geochemistry, pore structure, gas content and continuous thickness of shale, and the exploration potential of shale gas in this area is evaluated. The results indicate that the content of brittle minerals in the shale of well QX1 is 65.29% to 95.22% (average of 82.10%). The total organic carbon (TOC) content ranges from 2.06% to 12.10% (average of 5.64%). The organic matter maturity (Ro) within the range of 2.29–2.67%, and the kerogen type is identified as type I. The shale samples from the Niutitang Formation have high TOC content, suitable thermal maturity, and a favorable kerogen type, suggesting good gas generation potential. The results of scanning electron microscopy (SEM) show that intergranular pores, intragranular pores and microfractures are developed in the shale of well QX1, which can provide sufficient storage space for shale gas. The shale exhibits a continuous thickness of 105.66 m in the QX1 well, comprising a gas-bearing interval of 32.89 m at the top (with an effective continuous thickness of 18 m) and a hydrocarbon source rock layer of 75.78 m at the bottom. In comparison with other shale gas regions, Niutitang Formation shale in Northern Guizhou exhibits characteristics such as favorable gas generation conditions, greater storage conditions, excellent gas-bearing, strong frackability, and substantial continuous thickness, it has greater potential for shale gas exploration.

Petrophysical Properties Evaluation Using Well Logging of Jeribe Formation in Mansuriya Gas Field Diyala Governorate, Eastern Iraq

Al-Mansuriya gas field is regarded as one of Iraq's most important gas fields because of its good economic gas reserves. The major gas reserves of the Mansuriya field are situated in the Jeribe Formation. The present study aims to determine the petrophysical properties of the Jeribe Formation in the Mansuriya gas field by using the interpretation of different well logs for the open wells MN-1, MN-2, MN-3, and MN-4. The Jeribe Formation was divided into several reservoir units depending on the final results of CPI computer processing interpretation using the Interactive Petrophysics program (Techlog). According to the results of the CPI, the Jeribe Formation in the Mansuriya gas field was divided into seven units, which are J1, J2, J3, J4, J5, J6, and J7. Matrix definition (MID) and density-neutron cross plots indicate that the lithology of the Jeribe Formation consists of a large proportion of dolomite and limestone and a little anhydrite, also in the direction of the gas evident in the Jeribe Formation. The Gamma-ray log showed that the volume of the shale is very small in the Jeribe Formation, and the formation may be clean of shale content. The reason for this small reading is the presence of some radioactive materials in the rocks of formation. Through the readings of the RHOB and NPHI logs and the results of cutoff boundaries, we can conclude that units J1 and J6 represent non-reservoir units and can be considered a cap rock for the reservoir units, and the units J2, J3, J4, and J5 are the main reservoir units for Jeribe Formation according to CPI results and the results of high porosity in these units, as they are characterized by the porosity of up to 24% and water saturation of 40 to 60%, which makes them reservoirs of high quality. The Mn-4 well showed different results from the rest of the wells, and none of its units can be considered a reservoir due to the large water saturation volume.

Pore Structure and Factors Controlling Shale Reservoir Quality: A Case Study of Chang 7 Formation in the Southern Ordos Basin, China

The lithofacies types, pore structure differences, and main controlling factors on the shale reservoirs are vital problems that need to be addressed in the process of shale oil exploration and development. This study explores the Luohe oilfield in the southern Ordos Basin, which is composed of organic-rich shale in the Chang 7 member, to clarify the reservoir properties and analyze major factors affecting the reservoir quality. The shale reservoir can be divided into five lithofacies using ternary diagrams of TOC, argillaceous minerals, and siliceous minerals: high organic-rich siliceous shale (HOSS), high organic-rich argillaceous shale (HOAS), medium organic-rich siliceous shale (MOSS), medium organic-rich argillaceous shale (MOAS), and low organic-rich shale (LOS). The type of organic matter in the studied samples is mainly Type I kerogen and Type II kerogen, predominantly Type II1 kerogen. The kerogen mostly lie within the mature zone in the study area. Various types of pores have been identified in the studied shale: intergranular pores, intragranular pores, intercrystalline pores, organic matter pores, and seams around organic matter. The pores are commonly nanoscale to micrometer in scale, with diameters ranging from 10 nm to several microns. The S1 content in shale is positively correlated with the macropore content, indicating that macropores in shale are the main effective oil storage spaces and are important for oil-bearing reservoirs. There is a good positive relationship between the macropore volume of shale and the content of organic matter. Organic matter in the shale can be beneficial for generating organic matter pores, dissolution pores, and seams at organic matter edge, resulting in better physical properties of shale reservoirs. There is a negative relationship between the quartz/feldspar content and macropores content, indicating that quartz and feldspar are detrimental for the macropore volume development. The lithofacies type is one of the important factors controlling the macropore volume. MOAS and HOAS are favorable lithofacies for the development of macropores. The findings of this study can be utilized for hydrocarbon exploration and development in the lacustrine shale formation of the Ordos Basin and other similar basins.

Numerical simulation of resistivity and saturation estimation of pore-type gas hydrate reservoirs in the permafrost region of the Qilian Mountains

Abstract The pore-type hydrate reservoirs in the permafrost region of the Qilian Mountains (PRQM) have complex characteristics, including low porosity, low permeability, high shale content, and conductive minerals. Currently, the research on the electrical properties of these reservoirs still needs to be sufficiently in depth, and there are limitations in well-logging evaluation methods. To fill in this gap, a conductivity model of pore-type gas hydrate reservoirs (GHRs) is established based on the pore-combination modeling theory to investigate the influencing factors of the resistivity characteristics of GHRs through numerical simulations. The comparison between the laboratory-measured resistivity of different hydrate saturations and the results of the calculated model shows good agreement, indicating the accuracy of the conductivity model in describing the electrical characteristics of GHRs in the PRQM. Compared to conductive minerals, the numerical simulation results indicate that the high shale content is the main reason for the decrease in resistivity of pore-type GHRs in the study area. The hydrate saturation evaluation of well DK-3 from 386.3 to 393.6 m depth shows that the hydrate saturation ranges from 5.1 to 66.4%, with an average value of 44.0%. The identified hydrate interval using this model is consistent with the actual hydrate interval encountered during the drilling. This study, as an innovation, can help clarify the conductive mechanism of pore-type GHRs in the PRQM and provide more accurate parameters for evaluating gas hydrate resources in the study area.

Nuclear magnetic resonance study on wettability of shale oil reservoir

In order to identify and evaluate reservoir wettability, so as to select suitable mining methods to improve oil recovery, wettability evaluation through one-dimensional (1D) and two-dimensional (2D) nuclear magnetic resonance (NMR) technology combined with physical simulation experiments was carried out in this study, and the feasibility of the experimental method was verified by contact Angle method. According to the principle of hydrophilic inorganic content and hydrophobic organic content of shale, the wettability can be evaluated through vacuum self-imbibition oil and self-imbibition water physical simulation experiments combined with 1D NMR technology, that is, total water absorption can be considered as inorganic content, organic content can be obtained by subtracting total water absorption from total oil absorption, and adsorbed oil content can be obtained by subtracting pore volume from total oil absorption. In addition to the wettability measurement by contact Angle method to verify the experimental method, the occurrence ratio of adsorbed oil can also be verified twice by 2D NMR spectrum. The results show that the error between the proportion of adsorbed oil measured by 2D NMR spectrum and that measured by self-imbibition method is within 4%. In the saturated oil-bound water state, the bound water is within the relaxation interval of 1&amp;lt;T1&amp;lt;10 ms and 1&amp;lt;T2&amp;lt;10 ms, and the oil signal is within the relaxation interval of T1&amp;gt;10 ms and T2&amp;gt;10 ms. And the relaxation time of aqueous phase moved to the right compared with that in the saturated water state, the interaction force between water and the pore wall was weakened, showing the characteristics of free fluid, and the rock sample became oil-wet, which was consistent with the wettability results measured by contact Angle. Therefore, the wettability of rock samples can be evaluated by 1D NMR technique combined with vacuum imbibition method, or by analyzing the changes of NMR spectra of aqueous phase in completely saturated water and saturated oil-bound water.

Seis2Rock: A Data‐Driven Approach to Direct Petrophysical Inversion of Pre‐Stack Seismic Data

AbstractThe inversion of petrophysical parameters from seismic data represents a fundamental step in the process of characterizing the subsurface, with applications ranging from subsurface resource exploration to geothermal, carbon capture and storage, and hydrogen storage. We propose a novel, data‐driven approach, named Seis2Rock, that utilizes optimal basis functions learned from well‐log information to create a direct link between pre‐stack seismic data and so‐called band‐limited petrophysical reflectivities. Seis2Rock is composed of two stages: training and inference. During training, a set of optimal basis functions are identified by performing singular value decomposition on one or more synthetic amplitude variation with offset gathers created from measured or rock‐physics synthesized elastic well logs. In inference, seismic pre‐stack data are first projected into a set of band‐limited petrophysical reflectivities using the previously computed basis functions; this is followed by regularized post‐stack seismic inversion of the individual properties. In this work, we apply the Seis2Rock methodology to a synthetic data set based on the Smeaheia reservoir model and to the open Volve field data set. Our numerical results reveal the ability of the proposed method in recovering accurate porosity, shale content, and water saturation models. Finally, the proposed methodology is applied in the context of reservoir monitoring to invert time‐lapse, pre‐stack seismic data for water saturation changes.

Integrating Well Logs and Core Data for Better Reservoir Characterization of Mamuniyat Formation, Murzuq Basin, Libya

Increasing the number of dry holes in the last two decades to more than twenty wells in Murzuq Basin necessitates a comprehensive reservoir evaluation study to resolve this issue. The current work combines well logging and core data analysis to precisely estimate petrophysical parameters and evaluate the Mamuniyat reservoir. The available data includes well logs from eleven wells and core data from one of the studied wells (I-14 Well). Utilizing well logs and core data, the Mamuniyat Formation is found to be made up of sandstone with a low shale content between 5 and 10%. It has effective porosity values that vary between moderate (13%) and good (16%), with oil saturation ranging from 62 to 91%. Using core data analysis, it was found that the grain density is 2.65 g/cc. A good match between the core-derived and log-derived porosity values is observed. It could be concluded that the Mamuniyat Formation is a sandstone reservoir with low shale volume, moderate effective porosity, and high oil saturation. The reason for the large number of dry holes in Murzuq Basin could be attributed to other factors other than reservoir quality.

Experimental Study of the Fluid Contents and Organic/Inorganic Hydrocarbon Saturations, Porosities, and Permeabilities of Clay-Rich Shale

Unlike conventional reservoirs, shale is particularly complex in its mineral composition. As typical components in shale reservoirs, clay and organic matter have different pore structures and strong interactions with fluids, resulting in complex fluid occurrence-states in shale. For example, there are both free water and adsorbed water in clay, and both free oil and ad/absorbed oil in organic matter. Key properties such as fluid content, organic/inorganic porosity, and permeability in clay-rich shale have been poorly characterized in previous studies. In this paper, we used a vacuum-imbibition experimental method combined with nuclear magnetic resonance technique and mathematical modeling to characterize the fluid content, organic/inorganic porosity, saturation, and permeability of clay-rich shale. We conducted vacuum-imbibition experiments on both shale samples and pure clay samples to distinguish the adsorbed oil and water in clay and organic matter. The effects of clay content and total organic matter content (TOC) on porosity and adsorbed-fluid content are then discussed. Our results show that, for the tested samples, organic porosity accounts for 26–76% of total porosity. The oil content in organic matter ranges from 29% to 69% of the total oil content, and 2% to 58% of the organic oil content is ad/absorbed in kerogen. The inorganic porosity has a weak positive correlation with clay content, and organic porosity increases with rising levels of organic matter content. The organic permeability is 1–3 orders of magnitude lower than the inorganic permeability.

Reservoir Characterization of the Upper Part of Qamchuqa Formation from Miran and Bazian Oilfields in Kurdistan Region, NE Iraq

Reservoir characterization of the upper part of Qamchuqa Formation at the wells of Miran West-2 (MW-2) and Bazian-1 (BN-1) is studied. This formation typically has low shale content at the BN-1 well. At the same time, in the MW-2 well, the middle part of the studied formation is dominated by shaly and shale intervals, possibly affected by the Sarmord and Balambo depositional environments. Although the upper part of Qamchuqa Formation is mainly composed of dolomite with minor dolomitic limestone, marl and shale are occasionally present. Furthermore, porosity values are commonly less than 15% in both wells; nevertheless, there are a few intervals where porosity significantly increases. The formation at the BN-1 well has a higher porosity than the MW-2 well. Moreover, the secondary porosity is relatively low as 4.0% at the MW-2 well, while in the well of BN-1, it ranges between &lt; 4.0% and 7.5%. The measured permeability of the formation suggests good permeability. According to the shale volume, porosity, and permeability, the upper part of Qamchuqa Formation is subdivided into three reservoir units. RU 1 at the MW-2 well and RU 2 at the BN-1 well have the most substantial reservoir properties. However, the lowest reservoir quality appears within RU 1 of the BN-1 well and RU 2 at the well of MW-2. Additionally, residual hydrocarbons constitute an extensive fraction of the pore spaces, while tiny portions of the moveable one can be discovered along all reservoir units of the formation. Finally, considering the hydrocarbon movability of the MW-2 well, the upper part of Qamchuqa Formation is defined by primarily movable oils in RU 1 and 2. In contrast, moveable oils are detected in almost all of the reservoir units of the BN-1 well.

Gas-in-place content and occurrence state of deep shale gas in the Luzhou area, Sichuan Basin, China

The exploration and development of deep shale gas has made significant breakthroughs, but due to the characteristics of deep shale gas, there is no recognized and effective method of evaluating gas-bearing. To effectively determine the gas-in-place (GIP) content and occurrence state of deep shale gas, a total of 909 shales were collected for the study utilizing pressure-holding and conventional coring technologies from Wufeng-Longmaxi Formations in the Luzhou area, Sichuan Basin, China. The GIP content of the above shales was evaluated using various methods, including the USBM, polynomial fitting, ACF, MCF, process analysis and carbon isotope fractionation (CIF) methods. The accuracy of the above methods was verified through comparison with the gas content measured by pressure-holding coring. The results demonstrate that (1) the degassing content obtained from conventional coring ranges 0.06–2.13 cm3/g, averaging 0.64 cm3/g; the measured gas content obtained from pressure-holding coring ranges 2.19–11.91 cm3/g, averaging 7.16 cm3/g. The gas content obtained is significantly higher because pressure-holding coring samples have excellent sealing and minimal lost time. (2) The GIP content is underestimated by the USBM method, while the polynomial fitting, ACF, and MCF methods overestimate it. The process analysis and CIF methods can evaluate the GIP content of deep shales more accurately. Based on the comparative results of the adsorbed gas ratio calculated using the process analysis and the CIF methods (33.49% and 24.53%, respectively), it is recommended that the CIF method be given priority when evaluating deep shale gas-bearing. (3) The GIP content of deep shales in the Luzhou area calculated by the CIF method ranges 2.52–11.99 cm3/g, averaging 7.19 cm3/g; the adsorbed gas ratio accounts for 3.41%–53.32%, averaging 24.53%; and the lost gas ratio accounts for 54.01%–97.45%, averaging 86.38%. Compared with medium and shallow shale gas reservoirs in other areas, deep shale gas reservoirs in the Luzhou area have gas-bearing characteristics of high GIP content, low adsorbed gas ratio and high lost gas ratio, which restricts the applicability of traditional evaluation methods.

Geological controls on lithium production from basinal brines across North America

With increasing lithium (Li) demands for electric car batteries and grid storage, additional Li beyond traditional continental brines and hard-rock sources might be necessary. Elevated Li concentrations have been reported in select oil field brines. Li could be extracted from the large volumes of saline fluids produced by oil and gas wells or from new wells dedicated to Li production. However, the spatial distribution of Li+ concentrations, the rates at which fluids can be produced in areas with elevated Li+ concentrations, and potential sources of Li enrichment are not well characterized. To help identify additional sources of Li, this study investigates the concentration, origin, and potential production rates of Li from sedimentary basin brines across North America. New Li data from brines in various stratigraphic units in the Paradox Basin are combined with existing datasets from the basin and others across North America. New Li analyses of organic-rich shales in the Paradox Basin are also examined to provide insights into the origins of Li. Results from this study show the median Li+ concentration in oil and gas produced waters across North America is ~5 mg/L; these generally low concentrations are unlikely to support Li production. However, higher Li+ concentrations (>65 mg/L) are found in select basins and strata containing deep saline fluids, associated with evaporation of paleo-seawater and precipitation of halite and potash salts, that have not been flushed by meteoric recharge. High Li content of organic-rich shales (range: 20–440 ppm; median: 60 ppm) interbedded with evaporites in the Paradox Basin suggest fluid-rock interactions with diagenetically-altered shales and organic matter are one potential source of Li-enrichment in basinal brines. Observed fluid production and injection rates indicate that Li production will likely be highest in sandstone and carbonate formations with relatively high permeability. Potential Li production rates can vary by orders of magnitude even within these strata due to heterogeneity in both Li concentrations and permeability, as well as recovery efficiencies between 40 and 70 % with current technology. Targeted Li production wells, rather than relying on existing oil and gas wells, would likely be necessary to produce brines at sufficient volumes to support Li production at these low concentrations. Co-recovery of other critical elements or combination with other subsurface developments, such as geothermal energy production, may make Li production from sedimentary basin fluids more viable.

Sedimentology and geochemistry of the Upper Permian transitional shale, Western Guizhou, China: Implications for the environmental effect of the Emeishan large igneous province and organic matter accumulation

The marine-continental transitional shale of the Upper Permian Longtan Formation serves as a crucial target for both shale gas exploration and development, as well as a significant research object of the dramatic geological events during the Middle-Late Permian period. In this study, X-ray diffraction (XRD), polished section, scanning electron microscopy (SEM), energy spectrum analysis (EDS), total organic carbon content (TOC) and elemental geochemistry were conducted to elucidate the sedimentological and geochemical characteristics of the transitional shale in the Longtan Formation and the underlying Emeishan basalt in Western Guizhou. Additionally, the paleoenvironment conditions, the environmental effect of the Emeishan large igneous province and the organic matter enrichment mechanism of the transitional shale are investigated.The sedimentological and geochemical proxies reveal that influenced by seawater and river, the transitional shale of the Longtan Formation in western Guizhou was deposited in a marginal tidal flat-lagoon environment under a warm and humid paleoclimate, anoxic condition, brackish to saline bottom water, high terrigenous detrital input and high sedimentation rate condition. The mineral and elemental composition characteristics show that the transitional shale was predominantly derived from Emeishan basalt, supplemented by contributions from volcanic ash and hydrothermal activity. This suggests that following the eruption of the Emeishan large igneous province in Middle-Late Permian transition, the paleogeographic pattern of high in the west and low in the east was formed in the Upper Yangtze region. The weathering products of the Emeishan basalt were the main source of the Longtan Formation. Intense volcanic activities in the earliest Wuchiapingian potentially induced cooling of the climate, and the elements carried by hydrothermal input likely enhanced paleoproductivity and increased seawater salinity, and was conducive to the suboxic-anoxic water condition.The organic matter contents in transitional shale are extremely high with the highest organic matter content (>20%) of the shale deposited in mire, followed by the shale deposited in tidal flat (10%), whereas the lagoonal shale, predominant in the Longtan Formation, displays the lowest organic matter content (5%). The organic matter enrichment mechanism of transitional shale is primarily attributed to a “preservation model”. The suboxic-anoxic condition and brackish-saline water were conducive to the organic matter preservation. The primary productivity was low and organic matter mainly came from terrestrial higher plants. The warm and humid climate strengthened terrestrial weathering and erosion, consequently increasing terrigenous organic matter input and sedimentation rate. Elevated sedimentation rate reduced the decomposition time of organic matter, thereby also facilitating organic matter preservation. However, the correlations between TOC content and geochemical proxies in lagoonal shale suggest that the warmer and more humid paleoclimate may have increased terrigenous detrital influx and diluted the organic matter content.

Evaluating the effect of organic matter contained in shale on hydraulic fracturing of infill-well

Organic matter which is scattered uniformly in shale can respond to the applied stress and result in the variation of stress field. However, the effects of organic matter content in organic-rich shale on stress interference have not been well considered during developing infill-wells. A fully coupled numerical model is proposed in this paper to consider the whole flow spectrum of shale gas and investigate the effect of organic matter content on stress variation and fracture propagation in infill-well. Through simulating the production and fracturing process with only one set of code, some conclusions can be drawn that the alteration angle of the maximum horizontal principal stress increases and then decreases with the production time. Furthermore, the shrinkage of organic matter enlarges the alteration angle and the magnitude of the maximum horizontal principal stress. Certainly, the optimal fracturing effect in the infill-wells vary due to the different mass fraction of organic matter. This study not only helps to understand the effect of mass fraction of organic matter on stress variation and fracture propagation, but also provides theoretical support for increasing production from shale gas reservoirs.

Integrated workflow incorporating the Hurst exponent and interval inversion for evaluating groundwater formations

A novel well-log-analysis approach is presented for an improved prediction of petrophysical properties in groundwater formations. Geophysical well logs are simultaneously processed for quantifying the lithology, storage capacity, and water flow parameters. A fully automated data processing workflow is proposed, the feasibility of which is assured by an appropriate starting model set by the joint application of factor analysis and the Hurst exponent, and a solution of a highly overdetermined inverse problem. The Hurst exponent is used for zone boundary detection, which assists the series expansion-based interval inversion method applied for estimation of the petrophysical parameters of clastic formations. The hydraulic conductivity as a well log is directly derived from the inversion results. The workflow is tested using both synthetic data contaminated with 5% Gaussian distributed noise and real data collected from a thermal water well in Baktalórántháza, eastern Hungary. At the test site, the Hurst exponent extracted from the wireline logs allows one to divide the processed interval into subzones around the Pleistocene-Miocene boundary. The observed wireline logs are inverted to estimate the volumetric parameters (porosity, shale content, water saturation, etc.) of the same zones. The predicted parameters, including hydraulic conductivity, reveal that Pleistocene sediments contain good aquifers with formation quality varying with depth. The shale volume and hydraulic conductivity logs show a proper match with the core data, which confirms the results of the comprehensive analysis. The suggested workflow is recommended for the evaluation of groundwater formations located in different depth domains, from unsaturated sediments to geothermal reservoirs.

Main controlling factor and mechanism of gas-in-place content of the Lower Cambrian shale from different sedimentary facies in the western Hubei area, South China

The Lower Cambrian shale gas in the western Hubei area, South China has a great resource prospect, but the gas-in-place (GIP) content in different sedimentary facies varies widely, and the relevant mechanism has been not well understood. In the present study, two sets of the Lower Cambrian shale samples from the Wells YD4 and YD5 in the western Hubei area, representing the deep-water shelf facies and shallow-water platform facies, respectively, were investigated on the differences of pore types, pore structure and methane adsorption capacity between them, and the main controlling factor and mechanism of their methane adsorption capacities and GIP contents were discussed. The results show that the organic matter (OM) pores in the YD4 shale samples are dominant, while the inorganic mineral (IM) pores in the YD5 shale samples are primary, with underdeveloped OM pores. The pore specific surface area (SSA) and pore volume (PV) of the YD4 shale samples are mainly from micropores and mesopores, respectively, while those of the YD5 shale samples are mainly from micropores and macropores, respectively. The methane adsorption capacity of the YD4 shale samples is significantly higher than that of the YD5 shale samples, with a maximum absolute adsorption capacity of 3.13 cm3/g and 1.31 cm3/g in average, respectively. Compared with the shallow-water platform shale, the deep-water shelf shale has a higher TOC content, a better kerogen type and more developed OM pores, which is the main mechanism for its higher adsorption capacity. The GIP content models based on two samples with a similar TOC content selected respectively from the Wells YD4 and YD5 further indicate that the GIP content of the deep-water shelf shale is mainly 3−4 m3/t within a depth range of 1000–4000 m, with shale gas exploration and development potential, while the shallow-water platform shale has normally a GIP content of <1 m3/t, with little shale gas potential. Considering the geological and geochemical conditions of shale gas formation and preservation, the deep-water shelf facies is the most favorable target for the Lower Cambrian shale gas exploration and development in the western Hubei area, South China.