Shale Formation Research Articles

New Advance in the Study of Shale Oil Generation Peak Determination and Diagenetic Pore Evolution

Shale formations globally are widely distributed with abundant resources and varied thermal maturation ranges. However, the understanding of shale’s oil generation peak, diagenetic stages, and pore evolution remains incomplete. This study investigates shale samples of varying maturities and organic matter content from representative oil and gas basins in China and the United States. Comprehensive characterization was conducted using thermal simulation, rock X-ray diffraction analysis, N2 and CO2 adsorption, and mercury injection analysis. The study delineates the hydrocarbon generation process in shale, identifies the oil generation threshold, determines the peak oil generation, and categorizes shale’s diagenetic stages based on clay minerals and pore evolution. The results indicate: (1) highly mature shale exhibits delayed hydrocarbon expulsion and peak oil generation, starting at Ro values greater than 0.75% and reaching peak oil generation at Ro levels surpassing 1.2%. In contrast, peak oil generation in less mature shale initiates at Ro values of 1.1%, providing a more precise depiction of the shale’s diagenetic evolution stages; (2) the higher the TOC content of shale, the greater its hydrocarbon generation capacity, showing a robust positive correlation between hydrocarbon generation and TOC; (3) the diagenesis and pore evolution of shale can be categorized into four distinct stages: the early diagenesis stage (Ro < 0.5%), dominated by mesopores, and with reduced pore volume and surface area; the middle diagenesis stage A (0.5%–1.1%), where shale pore volume has been enhanced while the surface area has been reduced; the middle diagenesis stage B (1.1%–2.0%), where an initial decrease followed by an increase in mesopore volume occurs, along with a modest increase in macropores; and the late diagenesis stage (Ro > 2.0%), with increased organic pores and microfractures, while both pore volume and surface area expand. The study suggests that a Ro of 1.1% marks the peak oil generation period for shale, occurring during the early stage of middle diagenesis, characterized by larger pore volume and surface area, crucial for shale oil and gas enrichment.

Effect of calcium contamination on lignosulfonate mud, lime mud, and potassium chloride mud

A significant amount of the oil produced in Turkiye is extracted from the Southeastern Anatolia Region. In the drilling operations conducted around Batman and Diyarbakir, which are key areas for oil production in this region, formation-related problems are encountered, leading to increased drilling costs and time loss. The primary issues among these problems are the wellbore stability and the contamination of drilling mud with clay and calcium. In this study, experimental investigations were conducted in wells A-1, A-2, and A-3 located in region A, and well B-1 located in region B in the Batman and Diyarbakir areas. The investigations observed formation-related well stability issues and contamination of drilling mud with calcium and clay. Drilling mud experiments based on actual well data were conducted to address the changes in formation-related drilling mud. In wells A-1 and B-1, the drilling of formations containing gypsum and anhydrite was carried out using lignosulfonate mud, during which heavy calcium contamination occurred in the system mud, causing problems in the drilling operations. In well A-2, the drilling of gypsum and anhydrite in the Kayaköy formation, and shale and marl formations in the Kastel and Karadut formations, was done using KCl/Polymer mud. Experiments conducted on the drilling mud observed changes in the mud and examined the issues arising in the drilling operations. In well A-3, the drilling of rocks belonging to the same formations was performed, and lime mud was used in this well to counteract the possibility of gas influx, calcium contamination, and carbonate-bicarbonate contamination. The calcium concentration ranged from 120 to 800 mg/l in A-1 well, 80–800 mg/l in A-2 well, 440–680 mg/l in A-3 well, and 160–720 mg/l in B-1 well. Although calcium entrance to the drilling mud is inevitable during the drilling of calcium-bearing formation, this study shows that it is possible to drill these formations safely by the interventions at right times by the drilling fluid engineer.

Geological Conditions of Shale Gas Accumulation in Coal Measures

The shale of different potential layers is studied by using rock pyrolysis analysis, total organic carbon determination (TOC), kerogen microscopic component identification, mineral X-ray diffraction, scanning electron microscopy, and low-temperature nitrogen adsorption experiments. The results are as follows: (1) Shishui Formation of the Lower Carboniferous and Longtan Formation of the Upper Permian are the two most important shale gas reservoirs in the Chenlei Depression. The sedimentary environment of the target shale is a marine land interaction facies coastal bay lagoon swamp sedimentary system. Two sedimentary facies of tidal flat facies, subtidal zone, and lagoon swamp facies are developed. (2) The organic matter types of shale are Type III and II2, with TOC content greater than 1%. The maturity of shale samples is relatively higher (Ro,max is above 2%), which means they have entered the stage of large-scale gas generation. The overall brittle mineral content of the target shale sample is relatively higher (above 40%), which is conducive to artificial fracturing and fracture formation in the later stage, while an appropriate amount of clay minerals (generally stable at 40%) is conducive to gas adsorption. (3) The overall pore structure of the water measurement group and Longtan group is good, with a higher specific surface area and total pore volume (average specific surface area is 12.21 and 8.36 m2/g, respectively), which is conducive to the occurrence of shale gas and has good adsorption and storage potential. The gas content of the water measurement group and the Longtan Formation varies from 0.42 to 5 cm3/g, with an average of 2.1 cm3/g. It indicates that the water measurement group and the Longtan Formation shale gas in the study area have good resource potential.

Countercurrent Imbibition in Porous Media with Dense and Parallel Microfractures: Numerical and Analytical Study

Summary Countercurrent imbibition is the process in which the wetting fluid spontaneously displaces the nonwetting fluid, while the nonwetting fluid is recovered at the wetting fluid inlet. It is a major mechanism for the recovery of shale oil, shale gas, and tight oil. In shale and tight formations, microfractures are highly developed. Specifically, some typical formations, such as continental shales, consist of dense and parallel microfractures (DPFs). In DPF systems, microfractures are segregated by low-permeability matrix layers, while the very close distance betwen neighboring microfractures results in strong capillary correlation. The underlying assumptions of the classical dual-porosity (DP) model break down. Despite extensive studies on layered media, there is still no suitable model to describe imbibition in the DPF system at the representative elementary volume (REV) scale. In this study, we first numerically simulate countercurrent imbibition in DPF systems with fine grids, adopting typical continental shale parameters. For imbibition parallel to microfractures, two distinct stages are identified: an early stage where fractures are not correlated and a late stage where neighboring fractures are strongly correlated by capillarity. In both stages, cumulative oil production (Q) is proportional to the square root of imbibition time (t1/2), while the prefactors are very different. The late stage is the dominant stage in oil recovery. We note that the matrix permeability rarely contributes to imbibition parallel to microfractures at the late time, indicating that the matrix’s role here is to store fluid rather than to provide flow resistance. In addition, we rationalize the failure of the classical DP model, as it significantly overestimates fracture-matrix fluid exchange near the displacement front. Similarly, for imbibition perpendicular to microfractures, Q is also proportional to t1/2 in the late stage. After elucidating the mechanisms of fracture-fracture capillary interaction, we successfully derive analytical solutions for uni-directional countercurrent imbibition kinetics in DPF systems at the late stage, for imbibition parrallel and perpendicular to microfractures, respectively. We accordingly propose an equivalent REV scale model and examine it with fine-grid simulations. We highlight the importance of adopting anisotropic relative permeability in this DPF system at REV scale for reservoir simulation rather than simply adopting anisotropic absolute permeability. This presents a new challenge for numerical simulations at reservoir scale.

Synthetic Chemicals as Potential Tracers of Impacts of Fracturing Fluids on Groundwater

Application of hydraulic fracturing to produce “unconventional” oil and gas from shale formations and other low-permeability geological units has raised concerns about the potential environmental impacts, including potential adverse effects of fracturing fluids (FF) on groundwater. In this study, laboratory batch test experiments and new analytical methods were developed to analyze FF chemicals as potential indicators (tracers) to detect impacts of fracturing fluids on groundwater. The tests, conducted over 101–196 days, included FF with synthetic chemicals (~40,000–4,000,000 µg/L), placed in batches with groundwater and sediment at 5° and 25 °C, along with sterile controls. Using the new methods, measurable concentrations of the FF chemicals were many orders in magnitude lower (~3000 to 3,000,000 X) compared to their concentrations in synthetic fracturing fluids, indicating that these chemicals are excellent candidates as indicators of FF contamination in groundwater, if they are relatively persistent, and not prone to extensive loss by sorption during migration in the subsurface. Variable sorption and degradation of the chemicals was observed in both batch and column tests. Sorption was negligible (sorption coefficient, Kd~0.0) for some synthetic chemicals (polyethylene glycol, ethanolamines, isopropanol, and ethyl hexanol) in some tests. At the other extreme, strong sorption was observed for some of the higher molecular weight cocamido propyl betaine (max Kd = 1.17) and polyethylene glycol (max Kd = 1.12) components, and triethanolamine (max Kd = 0.47) in other tests. Apparent loss by degradation was observed for each chemical in some tests, but negligible in others. The shortest apparent half-lives were for isopropanol and ethyl hexanol at 25 °C (t½ < 11 days), and the most persistent synthetic chemicals were polyethylene glycols (t½ ≥ 182 d) and the ethanolamines (t½ ≥ 212 d). Of the potentially diagnostic FF chemicals investigated, the relatively hydrophilic and persistent lower molecular weight polyethylene glycols are some of the most promising as potential indicators of contamination of groundwater by FF.

Investigation on the plugging mechanism of nanocomposite polyacrylate copolymers in water-based drilling fluids: Experiments and applications

The plugging of nanopores and cracks in shale formation has become the critical technology that promotes the development of shale gas. Herein, nanocomposite polyacrylate (Poly-TALC) copolymers were successfully prepared by emulsion polymerization using butyl acrylate and triallyl isocyanurate as the raw material. Poly-TALC was characterized by fourier transform infrared spectroscopy (FTIR), laser light scattering particle size analysis, scanning electron microscope (SEM) and thermogravimetric analysis (TGA). The rheological properties and plugging performance of Poly-TALC were evaluated by a six-speed rotational viscometer, filter cake permeability test, core permeability test and pressure transfer experiment. Results revealed that Poly-TALC exhibited a particle size distribution ranging from 75.27 to 95.29 nm, while maintaining notable stability at 327.75 °C. Upon the addition of Poly-TALC to the drilling fluid, both the apparent viscosity and plastic viscosity insignificantly changes. At a Poly-TALC dosage of 1.0%, the filter cake's permeability was 1.2 × 10−5 μm2 with a plugging rate of 56.9%, while the permeability of the core was 1.2 × 10−6 μm2 with a plugging rate of 84.0%. The decrease in permeability was not significant beyond a Poly-TALC dosage of 1.0 wt%. Pressure transfer experiments demonstrate that Poly-TALC is able to form a multi-stage dense seal within the rock core, which can effectively prevent formation water from immersing into shale formation and improve shale wellbore stability.

Problem Solving of Hole Enlargement in Shale Formation Using XRD and CEC Analysis Approach: A Case Study of Well HES-003 in the North West Java Region, Indonesia

Problem Solving of Hole Enlargement in Shale Formation Using XRD and CEC Analysis Approach: A Case Study of Well HES-003 in the North West Java Region, Indonesia

Improving Shale Stability through the Utilization of Graphene Nanopowder and Modified Polymer-Based Silica Nanocomposite in Water-Based Drilling Fluids

Shale formations present significant challenges to traditional drilling fluids due to fluid infiltration, cuttings dispersion, and shale swelling, which can destabilize the wellbore. While oil-based drilling fluids (OBM) effectively address these concerns about their environmental impact, their cost limits their widespread use. Recently, nanomaterials (NPs) have emerged as a promising approach in drilling fluid technology, offering an innovative solution to improve the efficiency of water-based drilling fluids (WBDFs) in shale operations. This study evaluates the potential of utilizing modified silica nanocomposite and graphene nanopowder to formulate a nanoparticle-enhanced water-based drilling fluid (NP-WBDF). The main objective is to investigate the impact of these nanoparticle additives on the flow characteristics, filtration efficiency, and inhibition properties of the NP-WBDF. In this research, a silica nanocomposite was successfully synthesized using emulsion polymerization and analyzed using FTIR, PSD, and TEM techniques. Results showed that the silica nanocomposite exhibited a unimodal particle size distribution ranging from 38 nm to 164 nm, with an average particle size of approximately 72 nm. Shale samples before and after interaction with the graphene nanopowder WBDF and the silica nanocomposite WBDF were analyzed using scanning electron microscopy (SEM). The NP-WBM underwent evaluation through API filtration tests (LTLP), high-temperature/high-pressure (HTHP) filtration tests, and rheological measurements conducted with a conventional viscometer. Experimental results showed that the silica nanocomposite and the graphene nanopowder effectively bridged and sealed shale pore throats, demonstrating superior inhibition performance compared to conventional WBDF. Post adsorption, the shale surface exhibited increased hydrophobicity, contributing to enhanced stability. Overall, the silica nanocomposite and the graphene nanopowder positively impacted rheological performance and provided favorable filtration control in water-based drilling fluids.

Novel analytical solution for solvent-solute flow: Application to pressure transmission testing of reactive shales

Coupled solvent-solute flow is a common phenomenon observed while drilling shale formations using water-based fluids, leading to unfavorable outcomes. Designing optimal fluid formulation requires laboratory tests, such as pressure transmission tests, to evaluate shale-fluid interactions. In this study, an analytical solution was derived for the coupled flow of solvent-solute under pressure transmission testing conditions. It was derived based on the semi-infinite domain solution employing the method of images. The solution was then verified against the semi-analytical solution from the literature. The analysis of the solution revealed that early time pressure response at the outer boundary is primarily governed by hydraulic diffusivity while late time response is by ion diffusion. It also showed that the coefficient of lambda, introduced during derivations, quantifies the chemical effects. In addition, sensitivity analysis was conducted to better understand how variations in key parameters impact the overall transport processes within reactive shales. Finally, a good agreement was obtained by comparing the analytical solution with experimental data from various published sources. The solution will help researchers in gaining new insights into the shale fluid interactions and designing optimal fluid formulations.

The influence of different diagenesis on the elastic properties of different shale lithofacies: a case study of the upper Permian Wujiaping formation in East Sichuan Basin, China

Understanding the impact of diagenesis on the elastic properties of organic-rich shale reservoirs is essential for evaluating unconventional hydrocarbon reservoirs and interpreting seismic data. Recent advancements in the exploration of the Permian Wujiaping Formation in the eastern Sichuan Basin indicate its potential to become a significant succession within the Sichuan Basin. However, the effect of different lithofacies in the Wujiaping Formation on shale elastic properties under varying diagenetic conditions remains unclear, hindering detailed reservoir interpretation. This study employs X-ray diffraction, thin section analysis, scanning electron microscopy, organic geochemistry, and dynamic elastic property tests to investigate the Wujiaping Formation shale. The results reveal three primary lithofacies types: argillaceous shale, mixed shale, and siliceous shale. Argillaceous shale, subjected to intense compaction, forms a dense rock framework of oriented clay minerals, characterized by low porosity (1.66%), low elastic wave velocity (4122.30 m/s), low elastic modulus (2174.59 m/s), and high Poisson's ratio (32.24 GPa). Mixed shale, dominated by carbonates and quartz, exhibits a rock framework formed through dissolution and cementation, with high elastic wave velocity (5196.54 m/s), relatively high elastic modulus (2975.86 m/s), and moderate Poisson's ratio (58.53 GPa). Siliceous shale, comprising biogenic quartz particles, shows strong resistance to compaction. During hydrocarbon generation, it develops abundant organic matter pores, resulting in the highest porosity (2.36%), high elastic wave velocity (5177.92 m/s), high elastic modulus (2975.86 m/s), and low Poisson's ratio (62.23 GPa). The significant differences in mineral composition and diagenetic processes across the lithofacies lead to distinct elastic properties. This study provides a rock physics framework for the detailed seismic prediction of "sweet spots" in the Wujiaping Formation shale reservoirs and offers new insights into characterizing the diagenesis of unconventional shale reservoirs using geophysical properties.

Molecular Structural Characteristics and 3D Model Reconstruction of Organic Matter in Longmaxi Formation Shale.

The establishment of molecular structure modeling is an important means to study the pore characteristics of shale organic matter and is significant for molecular-level simulations of gas storage and diffusion. Using 13C NMR, FTIR, and XPS combined with the split-peak fitting technique, the structural characteristics of the aromatic structure, aliphatic structure, and oxygen functional groups of kerogen from the shale of the Longmaxi Formation, Wuxi County, Chongqing Municipality, were quantitatively characterized. A macromolecular structure model of the kerogen was also constructed by using the 2D macromolecular structure model construction method in combination with elemental analysis experiments. The results showed that the 2D single-molecule structural model of the sample consisted of 2 benzenes, 2 naphthalenes, 1 anthracene, 5 pyrenes, 1 pyridine, and 1 pyrrole. The C skeleton types were 93 protonated arylons, 39 bridged arylons, 6 carboxylons, 5 alkyl-substituted carbons, 2 oxygen-substituted carbons, 4 methylene carbons, and 3 methylons. The established 2D molecular structure formula was C152H82O12N2. The final 3D macromolecular structure model consisted of 14 2D molecular structures (structural formula C2128H1148O168N28), with the density set to 1.77 cm3/g, compressed in a cubic cell with an edge length of 3.05 nm. Finally, the adsorption results showed that the experimental adsorption of CO2 adsorption was less than the simulated adsorption, completing the validation of the model. The above study provides a method for determining the molecular structure of kerogen in the Longmaxi Formation shale, which can guide the study of the pore structure characteristics of the Longmaxi Formation shale.

Emerging advances in CO2 storativity and trappability within shale reservoirs

AbstractGeological carbon storage and utilization is widely regarded as the most realistic method of reducing carbon emissions throughout the energy transition era. In recent times, the implementation of carbon dioxide (CO2) injection has emerged as a potential method for increasing the recovery of hydrocarbon and facilitating the interaction of CO2 in shale reservoirs. This methodology enables the mitigation of total carbon emissions released into the earth's atmosphere. The concept of using CO2 geological sequestration in unconventional shale formations seems to be a prudent approach in responding to both the growing energy demand and mandating environmental requirements simultaneously. Shale reservoirs have received significant interest in the global context because to their substantial reserves and widespread distribution. This research offers a comprehensive analysis of the essential components involved in the sequestration of CO2 in shales, therefore improving the trapping and long‐term storage of CO2. In addition, it explores the extraction of hydrocarbons in this context. Gaining a comprehensive understanding of the fundamental factors that contribute to the storativity and trappability of CO2 is crucial for improving the displacement of methane gas (CH4) during shale gas recovery. This is particularly relevant in depleted the reservoirs of shale gas, where the aim is to enhance the effectiveness of in situ CO2 sequestration while reducing the leakage risk.

Influence of fracturing fluids on shale matrix permeability and micro-mechanical properties after chemical interactions

Geochemical interactions between shale and hydraulic fracture fluids (HFFs), principally mineral dissolution and precipitation, can result in alteration of matrix permeability and tendency of proppant embedment, ultimately impacting hydrocarbon migration through the shale formation. This study aimed to quantify changes of core permeability and micromechanical properties after shale-HFF chemical interactions. Extent of chemical alteration of the solid phase was characterized by synchrotron X-ray fluorescence mapping, micro-computed tomography, and scanning electron microscopy. Post-reaction brine was evaluated for elemental concentrations. Both low-carbonate and high-carbonate shale exhibited carbonate dissolution, an iron oxidation zone, and barite precipitates partially infilling secondary porosity. These reactions were more obvious in the high-carbonate shale but extended further into the low-carbonate shale. Pulse-decay permeability measurements generally revealed increase in permeability after reactions, whereas hardness and modulus reduction were observed only in reaction zones of high carbonate shale. Inevitable heterogeneity of natural shale samples resulted in large deviations in hydromechanical measurements both on the core scale and on the microscale.

Mechanical degradation of Longmaxi shale exposed to water-based fluids and supercritical carbon dioxide

Mechanical alterations in shale formations due to exposure to water-based fracturing fluids and supercritical carbon dioxide (ScCO2) significantly affect the performance of shale gas exploration and CO2 geo-sequestration. In this study, a hydrothermal (HT) reaction system was set up to treat Longmaxi shale samples of varying mineralogies (carbonate-, clay-, and quartz-rich) with different fluids, i.e. deionized (DI) water, 2% potassium chloride (KCl) solution, and ScCO2 under HT conditions expected in shale formation. Statistical micro-indentation was conducted to characterize the mechanical property alterations caused by the shale-fluid interactions. An in situ morphological and mineralogical identification technique that combines scanning electron microscopy (SEM) and backscattered electron (BSE) imaging with energy-dispersive X-ray spectroscopy (EDS) was used to analyze the microstructural and mineralogical changes of the treated shale samples. Results show no apparent changes in the Young’s modulus, E, and hardness, H, after treatment with DI water under room temperature (20 °C) and atmospheric pressure for 7 d. In contrast, E and H were decreased by 31.2% and 37.5% at elevated temperature (80 °C) and pressure (8 MPa), respectively. The addition of 2% KCl into DI water mitigated degradation of the mechanical properties. Quartz-rich shale specimens are the least sensitive to the water-based fracturing fluids, followed by the clay-rich and carbonate-rich shale formations. Based on in situ morphological and mineralogical identification, the primary factors for the mechanical degradation induced by water-based fluids include carbonate dissolution, clay swelling, and pyrite oxidation. Slight increases in the measured E and H and compression of porous clay aggregates were observed after treatment with ScCO2. The major factor contributing to the mechanical changes resulting from the exposure to scCO2 appears to be the competition between swelling caused by adsorption and compression of shale matrix.

Novel pterygotid sea scorpions from the Silurian and Devonian of Gondwana

Sea scorpions (eurypterids) are a group of extinct aquatic chelicerates that have a fossil record spanning the Ordovician through to the end Permian extinction. Due to their size and preservational potential, eurypterids have been well-documented in European and North American deposits, with less evidence from Gondwana. There is particularly limited evidence of the group from the Australian fossil record. To rectify this, we report new examples of pterygotid eurypterids from the late Silurian Wallace Shale and Early Devonian Merrimerriwa Formation, Mulga Downs Group in New South Wales. These specimens are assigned to Pterygotus sp. (Wallace Shale) and Jaekelopterus c.f. rhenaniae (Merrimerriwa Formation, Mulga Downs Group). The material is used to explore the extensive distribution and dispersal of these large, pelagic eurypterids and consider the position of the animals in their respective paleoecosystems. We conclude that these new records evidence the diversity of larger arthropods in Australian deposits and that ongoing documentation of these rare fossils is required to further understand the Paleozoic of Australia.

Discovery of nano organo-clay complex pore-fractures in shale and its scientific significance: A case study of Cretaceous Qingshankou Formation shale, Songliao Basin, NE China

A new pore type, nano-scale organo-clay complex pore-fracture was first discovered based on argon ion polishing-field emission scanning electron microscopy, energy dispersive spectroscopy and three-dimensional reconstruction by focused ion-scanning electron in combination with analysis of TOC, Ro values, X-ray diffraction etc. in the Cretaceous Qingshankou Formation shale in the Songliao Basin, NE China. Such pore characteristics and evolution study show that: (1) Organo-clay complex pore-fractures are developed in the shale matrix and in the form of spongy and reticular aggregates. Different from circular or oval organic pores discovered in other shales, a single organo-clay complex pore is square, rectangular, rhombic or slaty, with the pore diameter generally less than 200 nm. (2) With thermal maturity increasing, the elements (C, Si, Al, O, Mg, Fe, etc.) in organo-clay complex change accordingly, showing that organic matter shrinkage due to hydrocarbon generation and clay mineral transformation both affect organo-clay complex pore-fracture formation. (3) At high thermal maturity, the Qingshankou Formation shale is dominated by nano-scale organo-clay complex pore-fractures with the percentage reaching more than 70% of total pore space. The spatial connectivity of organo-clay complex pore-fractures is significantly better than that of organic pores. It is suggested that organo-complex pore-fractures are the main pore space of laminar shale at high thermal maturity and are the main oil and gas accumulation space in the core area of continental shale oil. The discovery of nano-scale organo-clay complex pore-fractures changes the conventional view that inorganic pores are the main reservoir space and has scientific significance for the study of shale oil formation and accumulation laws.

Multi-fracture growth behavior during TPDF in a horizontal well of multi-clustered perforations: An experimental research

Temporary plugging and diverting fracturing (TPDF), involving inner-fracture temporary plugging (IFTP) and inner-stage temporary plugging (ISTP), has been proposed as a widely applied technique in China, for promoting the uniform initiation and propagation of multi-clustered hydraulic fractures (HFs) in a horizontal well of the shale oil/gas reservoirs. However, how the key plugging parameters controlling the multi-fracture growth and the pumping pressure response during TPDF in shale with dense bedding planes (BPs) and natural fractures (NFs) is still unclear, which limits the optimization of TPDF scheme. In this paper, a series of TPDF simulation experiments within a stage of multi-cluster in a horizontal well were carried out on outcrops of Longmaxi Formation shale using a large-scale true tri-axial fracturing simulation system, combined with the acoustic emission (AE) monitor and computed tomography (CT) scanning techniques. Each experiment was divided into three stages, including the conventional fracturing (CF), IFTP and ISTP. Multi-fracture initiation and propagation behavior, and the dominant controlling parameters were examined, containing the particle sizes, concentration of temporary plugging agent (TPA), and cluster number. The results showed that the number of transverse HFs (THFs) and the overall complexity of fracture morphology increase with the increase in TPA concentration and perforation cluster number. Obviously, the required concentration of TPA is positively correlated with the cluster number. Higher peak values and continuous fluctuations of pumping pressure during TPDF may indicate the creation of diversion fractures. The creation of standard THFs during CF is favorable to the creation of diversion fractures during TPDF. Moreover, the activation of BPs nearby the wellbore during CF is unfavorable to the subsequent pressure buildup during TPDF, resulting in poor plugging and diverting effect. Notably, under the strike-slip fault stress regime, the diversion of THFs is not likely during IFTP, which is similar as the results of ISTP to initiate mainly the un-initiated or under-propagated perforation clusters. Three typical pressure curve types during TPDF can be summarized to briefly identify the hydraulic fracture diversion effects, including good (multiple branches or/and THFs can be newly created), fair (HF initiation along the slightly opened BPs and then activating the NFs), and bad (HF initiation along the largely opened BPs and then connecting with the NFs).

Hydrocarbon Generation Potential and Organic Matter Enrichment Mechanism of the Cambrian Marine Shale in the Tadong Low Uplift, Tarim Basin

AbstractCambrian shales in China and elsewhere contain abundant oil and gas resources. However, due to its deep burial and limited outcrop, there has been relatively little research conducted on it. The Cambrian shale of the Tadong low uplift in the Tarim Basin of western China, specifically the Xidashan–Xishanbulake Formation (Fm.) and overlying Moheershan Fm. provide a case study through the use of organic petrology, mineralogy, organic and elemental geochemistry, with the aim of analyzing and exploring the hydrocarbon generation potential (PG) and organic matter (OM) enrichment mechanisms within these shale formations. The results indicate that: (1) the Cambrian shale of the Tadong low uplift exhibits relatively dispersed OM that consists of vitrinite‐like macerals and solid bitumen. These formations have a higher content of quartz and are primarily composed of silica‐based lithology; (2) shale samples from the Xidashan–Xishanbulake and Moheershan formations demonstrate high total organic carbon (TOC) and low S2 content. The OM is predominantly type I and type II kerogens, indicating a high level of maturation in the wet gas period. These shales have undergone extensive hydrocarbon generation, showing characteristics of relatively poor PG; (3) the sedimentary environments of the Xidashan–Xishanbulake and Moheershan formations in the Tadong low uplift are similar. They were deposited in warm and humid climatic conditions, in oxygen‐deficient environments, with stable terrigenous inputs, high paleoproductivity, high paleosalinity, weak water‐holding capacity, and no significant hydrothermal activity; and (4) the relationship between TOC and the paleoproductivity parameter (P/Ti) is most significant in the Lower Cambrian Xidashan–Xishanbulake Fm., whereas correlation with other indicators is not evident. This suggests a productivity‐driven OM enrichment model, where input of land‐derived material was relatively small during the Middle Cambrian, and the ancient water exhibited lower salinity. A comprehensive pattern was formed under the combined control of paleoproductivity and preservation conditions. This study provides valuable guidance for oil and gas exploration in the Tarim Basin.

Environmentally friendly and temperature resistant water-based drilling fluids with highly inhibitory synthetic nanocellulose polymers for deep sea drilling

The ocean is rich in sustainable hydrocarbon. The process of extracting these resources poses challenges such as coexistence of low temperature and high temperature, high pressure of deepwater and unpredictable shale formations. A kind of ionic crosslinking polymer consisting of N, N-dimethylacrylamide (DMA), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), and Cellulose Nanofibers (CNF) (PADC), was synthesized to address these challenges. Cellulose was first oxidized to nanocellulose (CNF) through 2,2,6,6-tetramethylpiperidinyl-1-oxide (TEMPO) oxidation. Subsequently, the ionic crosslinking polymer, consisting of DMA, AMPS, and CNF, was synthesized using ionic crosslinking polymerization. The surface characteristics and morphology were characterized by transmission electron microscopy (TEM), nanoparticle size analysis, and zeta potential analysis. The structural composition was analyzed by Fourier Transform Infrared Spectroscopy (FT-IR). The shale inhibition mechanism was investigated through contact angle and pressure transmission experiments. The results indicated that the average length of PADC is approximately 1450 nm, with an average diameter of less than 100 nm and contains sulfonic acid groups. The shale contact angle increased from 16.75° to 82°, indicating that PADC increased the hydrophobicity of the shale by 390%. Pressure transfer experiments show that PADC can reduce shale permeability by 37%, which means PADC has good hydration inhibition performance. In addition, a drilling fluid system suitable for deep sea drilling was proposed. The drilling fluid system exhibits good rheological properties at 160 °C and 0 °C. The fluid loss after hot rolling at 160 °C is less than 12 mL. The linear expansion of shale core after 16 h is only 0.7%, and the rolling recovery rate at 160 °C is as high as 99.48%. Luminescent bacteria EC50 is 2.0 × 105 mg/L, which means it is non-toxic and environmentally friendly. And drilling fluid conforms to the power law flow model. Therefore, the drilling fluids proposed in this paper can meet the requirements of deep sea drilling in terms of rheological properties and filtration loss properties at 0–160 °C, and can seal shale pores and inhibit shale hydration through the ionic cross-linking PADC. This research offers insights into the utilization of cellulose in well drilling processes and provides references for designing deep sea drilling fluids.

Experimental study on shale-breaking of special-shaped cutter PDC bit

To enhance the drilling efficiency and extend the service life of PDC (Polycrystalline Diamond Composite) bits in shale formations, this study delves into the rock-breaking mechanisms of special-shaped cutters through a comprehensive experimental approach. This involves optimizing the cutter designs, conducting laboratory experiment and field testing. Among the various cutter geometries considered, concave, axe, planar, and triangular cutters are chosen as the focal points for unit rock-breaking experiments. These tests aim to assess their cutting loads and cutting specific energy to gain a deeper understanding of their performance characteristics. Based on experimental, the debris characteristics are analyzed. Based on the understanding of the shale-breaking characteristics of special-shaped cutters, field testing is performed using a novel PDC bit with a special-shaped cutter. Compared with planar cutters, the concave cutter and the triangular cutter generate lower cutting loads and cutting specific energy. Under identical conditions, the average cutting force and cutting specific energy of concave cutter at different cutting depths are reduced by 16.1% and 19.6% Specifically, the concave cutter generates the largest debris when operated under similar conditions, which is beneficial for increasing rock-breaking efficiency. Laboratory experiment indicate that compared to conventional drill bits, the novel drill bit experiences an increase in torque of approximately 9.8% with increasing WOB (weight on bit). Under high WOB, the ROP (rate of penetration) increases by about 75.4%, while the mechanical specific energy decreases by nearly 40%. Additionally, the novel bit vibration characteristics remain superior to conventional drill bits. Field testing shows that the average ROP of the novel bit and total footage drilled increase by up to 13.3% and 27.2%, respectively, in comparison with those for the conventional bit. The research results are helpful to speed up the efficiency of shale gas drilling.