Diagenetic Genesis and Evolution of Coal-Bearing Tight Sandstone Reservoir in the Yangxia Formation, Northern Kuqa Depression, Tarim Basin

Coal seams of the Yangxia Formation are widespread in the northern part of the Kuqa Depression in the Tarim Basin. During the thermal evolution of the coal seams, the generated fluids of different periods and natures have a significant impact on tight sandstone reservoirs. To further investigate the diagenetic characteristics and reservoir genesis of the tight sandstones due to the influence of coal seams, an in-depth exploration of the causes of dissolution and cementation in the reservoirs was conducted through thin-section casting, cathode luminescence, scanning electron microscopy, carbon-oxygen isotopic analyses, and X-ray diffraction of whole rock and authigenic clay minerals, along with burial evolution history and fluid evolution history. It is suggested that two phases of acidic fluids are mainly produced during the thermal evolution process of coal seams, including an early humic acid and a late organic carboxylic acid. The early phase humic acid plays a purifying role in reservoirs with coarse particles, rigidity-rich particles, and good permeability conditions. It selectively dissolves sedimentary calcareous mud and calcite, and the dissolution products are completely migrated. At the same time, it inhibits early carbonate cementation. The late organic carboxylic acid will dissolve potassium feldspar and some volcanic rock debris, and the dissolution products are difficult to migrate under the sealing conditions caused by lithological differences, which often take the cementation form of siliceous overgrowth and kaolinite or illite. In addition to the cementation resulting from the dissolution products of acidic fluids produced by the coal seams, the CO2-rich fluids generated by the coal seam thermal evolution will combine with ions such as Ca2+ from different sources, resulting in two phases of carbonate cementation. Based on the above research, this study summarizes a set of diagenetic evolution models for coal-bearing reservoirs.

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.

Organic Geochemical Evidence for the Formation of Condensate from Coaly Source Rocks in the Wumaying Buried Hill of the Huanghua Depression, Bohai Bay Basin

Although oil and gas from coaly source rocks have been widely discovered worldwide, the role of oil generated from coal measures in marine-continental coaly deposits during the Carboniferous-Permian period in the Bohai Bay Basin has long been a subject of debate. The recent discovery of a condensate reservoir in the Wumaying buried hill within the Huanghua Depression of the Bohai Bay Basin offers new potential insights into this issue. In this study, we employed organic geochemical methods to explore the possibility of the Carboniferous-Permian coal deposit being a primary source of the condensate. The distribution of light hydrocarbons and the biomarker assemblage indicate that the condensate did not undergo significant secondary alterations such as thermal cracking, gas invasion fractionation, or biodegradation. The hydrocarbon generation potential of the Carboniferous-Permian coaly source rocks suggests that they could be an important contributor to the formation of condensate. High pristine/phytane ratios (1.0-7.5), an abundant presence of benzene series, and the dominance of C29 steranes (>50%) within the condensate could be indicative of coaly organic matter. These features are comparable to those found in coaly source rocks. Moreover, the stable carbon isotopic compositions of n-alkanes in the condensate, ranging from -26.0 to -30.0‰, correlate well with those from coaly mudstone (-25.4 to -30.0‰). This suggests that the condensate of the Wumaying buried hill may predominantly originate from the Carboniferous-Permian coaly mudstone. When integrated with the geological background, the results distinctly demonstrate that the Carboniferous-Permian coaly source rocks have significantly contributed to the formation of the condensate reservoir in the Wumaying buried hill. This provides an essential reference for future exploration of oil and gas resources derived from the carboniferous-Permian coaly source rocks in the Bohai Bay Basin.

Elucidating the deactivation mechanism of beta zeolite catalyzed linear alkylbenzene production with oxygenated organic compound contaminated feedstocks

Zeolite catalyzed alkylation of benzene with long-chain α-olefins is a promising method for the detergent industry. Considering the long-chain α-olefins from Fischer-Tropsch synthesis always contain some oxygenated organic compounds, the effect of which on the alkylation of benzene with 1-dodecene was comprehensively investigated over beta zeolite herein. n-heptanol, n-heptaldehyde and n-heptanoic acid were selected as the model oxygenated organic compounds, and it was revealed that an obvious decrease of lifetime occurred when only trace amount of oxygenated organic compounds were added into the feedstocks. The deactivated catalyst was difficult to regenerate by extraction with hot benzene or coke-burning. A series of characterization tests complementary with DFT calculations revealed that the deactivation was mainly caused by the firm adsorption of oxygenated organic compounds on the acid sites. Further, comparison with the open-framework MWW zeolite revealed a similar effect of oxygenated organic compounds and deactivation mechanism for both beta and MWW, but beta is less sensitive to the oxygenated organic compounds. The main reason lies in the three-dimensional framework of beta, wherein the much higher adsorption energy of 1-dodecene makes it difficult to be replaced by oxygenated organic compounds. Additionally, beta could be regenerated more easily by extraction with hot benzene compared with MWW. But coke-burning caused a sharp decrease of its lifetime, which is mainly due to the decreased acid sites after calcination.

Effect of Low-Temperature Plasma-Modified Carbon Fibers on Impact Load Damage of Low-Density Oil-Well Cement

After large-scale exploitation of conventional oil and gas resources, most remaining resources are in highly depleted zones, where the fracture pressure of the formations is greatly reduced. Low-density oil-well cement prevents wellbore and formation fractures by reducing annular liquid column pressure and is one of the most commonly used cements in the oil and gas industry. However, cement sheaths made of low-density oil-well cement can be easily damaged due to the impact load generated during the well completion process. Incorporating carbon fibers into the cement matrix can effectively enhance the performance of cement sheaths. To ensure that carbon fibers can be closely combined with the cement matrix, low-temperature plasma modification technology was used in this study to pretreat the fibers. The mechanical properties of low-density oil-well cement incorporated with unmodified or modified carbon fibers were studied in detail under an impact load. The results of X-ray photoelectron spectroscopy revealed that the content of hydrophilic groups on the surface increased from 18.3 to 60.3% after the plasma treatment. The impact test results showed that the peak strengths of the cements cured at 60 °C for 14 days with 0.3% unmodified and modified carbon fibers could reach 37.01 ± 1.7 and 62.27 ± 1.7 MPa, respectively, under the impact load, i.e., an increase of 68.25% after the carbon fibers were treated with low-temperature plasma. Similarly, the absorbed energy increased from 15.59 to 44.31 J, and the energy absorption rate increased from 25.98 to 73.85%. Low-temperature plasma modification provided hydrophilic functional groups on the surface, significantly improving the interfacial bonding between the carbon fibers and cement matrix. The strengthened interaction was beneficial to extending the bearing time under the impact load and demonstrated a positive influence on the mechanical properties related to the impact resistance.

Toward Estimating CO2 Solubility in Pure Water and Brine Using Cascade Forward Neural Network and Generalized Regression Neural Network: Application to CO2 Dissolution Trapping in Saline Aquifers

Predicting carbon dioxide (CO2) solubility in water and brine is crucial for understanding carbon capture and storage (CCS) processes. Accurate solubility predictions inform the feasibility and effectiveness of CO2 dissolution trapping, a key mechanism in carbon sequestration in saline aquifers. In this work, a comprehensive data set comprising 1278 experimental solubility data points for CO2-brine systems was assembled, encompassing diverse operating conditions. These data encompassed brines containing six different salts: NaCl, KCl, NaHCO3, CaCl2, MgCl2, and Na2SO4. Also, this databank encompassed temperature spanning from 273.15 to 453.15 K and a pressure range spanning 0.06-100 MPa. To model this solubility databank, cascade forward neural network (CFNN) and generalized regression neural network (GRNN) were employed. Furthermore, three optimization algorithms, namely, Bayesian Regularization (BR), Broyden-Fletcher-Goldfarb-Shanno (BFGS) quasi-Newton, and Levenberg-Marquardt (LM), were applied to enhance the performance of the CFNN models. The CFNN-LM model showcased average absolute percent relative error (AAPRE) values of 5.37% for the overall data set, 5.26% for the training subset, and 5.85% for the testing subset. Overall, the CFNN-LM model stands out as the most accurate among the models crafted in this study, boasting the highest overall R2 value of 0.9949 among the other models. Based on sensitivity analysis, pressure exerts the most significant influence and stands as the sole parameter with a positive impact on CO2 solubility in brine. Conversely, temperature and the concentration of all six salts considered in the model exhibited a negative impact. All salts exert a negative impact on CO2 solubility due to their salting-out effect, with varying degrees of influence. The salting-out effects of the salts can be ranked as follows: from the most pronounced to the least: MgCl2 > CaCl2 > NaCl > KCl > NaHCO3 > Na2SO4. By employing the leverage approach, only a few instances of potential suspected and out-of-leverage data were found. The relatively low count of identified potential suspected and out-of-leverage data, given the expansive solubility database, underscores the reliability and accuracy of both the data set and the CFNN-LM model's performance in this survey.

Genesis and Accumulation Mechanism of Low-Rank CBM: A Case Study in the Jiergalangtu Block of Erlian Basin, Northern China

In order to elucidate the origin of coalbed methane (CBM) in the Jiergalangtu block of Erlian Basin, Inner Mongolia of China, gas components, stable isotope tests of 22 gas samples, radioisotope dating measurements, and water quality analysis of 15 coproduced water samples were evaluated. On account of the geochemical data and genetic indicators, including C1/C1-n, C1/(C2 + C3), and CO2/(CO2 + CH4) (CDMI) values, δ13C(CO2), Δδ13C(CO2-CH4), δ15N, and 3He/4He combined with vitrinite reflectance (Ro) (0.29-0.48%, avg. 0.35%) of Saihantala formation, the results indicate that methane in the Jiergalangtu block is mostly dominated by primary and secondary biological gas, 40.91% of the gas samples are secondary biogas and primary biogas accounts for 59.19%. Among them, methyl-type fermentation accounts for 31.82%, and carbon dioxide (CO2) reduction makes up 68.18%. CO2 reduction generally occurs region-wide but is mainly associated with the central part of the block, where CO2 depletion and 13C enrichment take place correspondingly. Methane and CO2 δ13C almost tend to isotopically light along the margin of the block, indicating that gas generation is significantly affected by the methyl-type fermentation pathway. Meanwhile, the genesis analysis of other gas components in CBM is also investigated, CO2 is mainly the associated product of microbial methanogenesis, and nitrogen (N2) is primarily from the atmosphere with a little amount from the earth's crust. Furthermore, the formation time of coalbed water has been dissected based on the hydrogeochemical properties of the coproduced water samples. The coalbed water exhibit a Na-HCO3 and Na-HCO3-Cl type and have a total dissolved solid (TDS) value ranging from 2458.58 to 5579.1 mg/L, with an average of 3440.55 mg/L. Moreover, comprehensive analysis of δD(H2O), δ18O(H2O), δ13CDIC, and the radioisotope dating index [3H, 14C(Fm) and 14C(BP)] indicates that the coalbed water was formed in the Quaternary Pleistocene and rarely replenished by the present surface water. The mechanism of CBM accumulation is basically sorted out by synthesizing the history of burial, heat, and hydrocarbon generation. The CBM formation can be divided into four stages. That is, microbial gas production approximately began at the beginning of the Early Cretaceous and reached the peak of thermogenic gas production in the middle and late Early Cretaceous. At the end of the Early Cretaceous, strata possibly began to uplift, and denudation led to gas escape. From Neogene to Pleistocene, glacial meltwater tended to penetrate into coalbed on a large scale, and N2 and CO2 also entered the coal seams, stimulating abundant secondary biological gas generation. Since Holocene, geological conditions including temperature and TDS have become hostile to biogas generation, and biogas generation tends to stop. Therefore, the Jiergalangtu block mainly represents sealed primary biological gas and secondary biological gas in CBM reservoirs.

Synthesis and Characterization of a Resin/Acrylamide-2-acrylamide-2-methylpropane Sulfonate-Diallyl Dimethyl Ammonium Chloride-N-vinyl-2-pyrrolidinone Polymer Microcapsule Gelling Agent for Oil and Gas Field Transformation

Deep carbonate rock oil and gas reservoir is an important support for increasing oil and gas storage and production at present. The environment of ultradeep and ultrahigh-temperature reservoirs has put forward higher technical requirements for reservoir modification acid technology. Moreover, gelling acid is the main acid solution for high-temperature reservoir acidizing transformation, with a temperature resistance of no more than 180 °C, and the gelling agent is one of the key factors restricting its high-temperature resistance performance. In this paper, AM, AMPS, DMDAAC, and NVP were used as monomers, oxidants, and reducing agents to prepare a high-temperature-resistant polymer gel through polymerization. At the same time, microcapsules were prepared by in situ polymerization using epoxy resin as the wall material. The indoor performance evaluation results indicate that the gelling agent is easily soluble in high-concentration acid solution and has good viscosity increasing effect. At 180 °C and 170 s-1 shear rate, 0.8% mass fraction of the gelling agent was dissolved in 20% mass fraction of hydrochloric acid. After shearing for 60 min, the viscosity remained at about 22.45 mPa·s, demonstrating good temperature resistance and shear resistance, and its performance was superior to existing commonly used gelling agent products.

Study on Matrix Damage and Control Methods of Fracturing Fluid on Tight Sandstone Gas Reservoirs

Hydraulic fracturing is a highly effective method for stimulating the development of gas reservoirs. However, the process of pumping fracturing fluid (FF) into the reservoir unavoidably causes damage to the surrounding matrix, leading to a decrease in the overall stimulation effect. To assess the extent of matrix permeability damage caused by the intrusion of FF, as well as its impact on the pore throat structure, and to propose appropriate measures to control this damage, we conducted a series of experimental studies on tight gas reservoirs. These studies included mercury intrusion, core flow, nitrogen adsorption, linear expansion, and contact angle measurements. The findings revealed that the damage inflicted on matrix permeability by FF was significantly greater than that caused by its gel-breaking counterpart. Surprisingly, the damage rate of the rejecting fluid to the matrix was found to be comparable to that of its gel-breaking counterpart. The fractal dimension (D2) was observed to have a strong correlation with surface area, pore volume, and mean pore size, making it an effective means of characterizing pore structure characteristics. After the rock samples were displaced by the formation water, the D2 value decreased, leading to a decrease in the complexity of the pore throat structure and an increase in matrix permeability. Conversely, the displacement of the FF increased the D2 value, indicating a gradual complication of the pore throat structure and a more uneven distribution of pore sizes. The inclusion of polyamide in antiexpansion FF, as well as its gel-breaking counterpart, proved to be effective in inhibiting the hydration and expansion of clay minerals, thereby reducing water-sensitive damage. Additionally, the use of surfactants with low surface tension enhanced the flowback rate of FF by increasing the contact angle and reducing the work of adhesion. This, in turn, helped to decrease the apparent water film thickness and expand gas flow channels, ultimately improving gas permeability.