Formation Of Gas Reservoirs Research Articles

Enrichment characteristics of deep shale gas in tectonically complex regions of the southeastern sichuan basin, China

In recent years, breakthroughs have been made in deep shale gas exploration in the Wufeng-Longmaxi formations in the complex tectonic region of the Sichuan Basin and southeastern margin, indicating promising prospects for exploration and development. This study focuses on the Nanchuan area of the complex tectonic region of the southeastern Sichuan Basin margin, using data from drilling wells and experimental analysis tests to investigate deep shale gas enrichment characteristics, particularly the effects of changes in the formation environment such as formation temperature and pressure on deep shale gas enrichment. The study concludes that: (1) The dominant sedimentary phase zone is the basis for hydrocarbon formation in shale gas reservoirs, with the Wufeng Formation–the first member of Longmaxi Formation in the study area—formed in a deep-water shelf sedimentary environment with high-quality shale development, which provides favorable material conditions for the formation of shale gas reservoirs. (2) Organic carbon content controls the degree of development of nanoscale organic matter pores, and the high-pressure-ultra-high-pressure environment helps maintain pores and improve the physical properties of deep shale. (3) Deep shale gas exhibits typical geological characteristics of high temperature, high ground stress, and exceptionally low permeability. The study finds the influence of temperature on the adsorption capacity of shale is more significant than that of pressure, and deep shale gas is primarily free gas. High pressure can slow down or inhibit gas flow, which is beneficial to shale gas preservation. (4) Gas diffusion is complex, with high temperature increasing the diffusion of gas, aggravating the migration and escape of gas, while high pressure can slow down or inhibit gas flow, which is beneficial to shale gas preservation. (5) The burial depth and pressure coefficient show a positive correlation, and the burial depth has a more significant effect on the pressure coefficient of syncline shale gas, indicating that preservation conditions of deep syncline shale gas reservoirs are becoming better. Residual syncline core with larger depths, inner-sag uplift, and slopes with reverse faults can be favorable targets for shale gas exploration in complex tectonic zones.

Effect of Sedimentary Facies Characteristics on Deep Shale Gas Desserts: A Case from the Longmaxi Formation, South Sichuan Basin, China

Shale gas is one of the hot spots of energy development. Due to the strong heterogeneity and low physical properties of shale gas reservoirs, and the complex influencing factors of pore development, it is necessary to conduct a comprehensive analysis of the control factors of high-quality reservoirs. The sedimentary characteristics, mineral composition, pore structure and controlling factors of high quality reservoir development are studied on the basis of thin section, scanning electron microscopy (SEM) and QEMSCAN analysis, X-ray diffraction (XRD), total organic carbon (TOC), Nano-CT scanning and Low-pressure N2 adsorption (N2GA) analysis on shale samples from the Longmaxi Formation in South Sichuan Basin. The results show the following: (1) According to lithology, sedimentary structure, organic carbon content and mineral composition, six sedimentary microfacies can be divided. (2) Organic matter pores are developed in organic-rich siliceous shale and organic-rich silty shale at the bottom of the first member of the Longmaxi formation, with average porosity of more than 5% and permeability of more than 2 × 10−3 μm2, which is conducive to the formation of high-quality shale gas reservoirs. (3) The contents of siliceous and TOC are positively correlated with porosity and specific surface area, while the contents of carbonate and clay minerals are negatively correlated with reservoir quality. (4) In the first member of the Longmaxi formation, the sedimentary water depth becomes shallower from bottom to top, and the sedimentary environment changes from a reduction to an oxidation environment. The contents of siliceous and organic matter decrease, while the contents of clay minerals and carbonate minerals show the opposite trend. The difference in sedimentary microfacies affects the distribution of mineral and organic matter and controls the heterogeneity of the shale reservoir.

Formation conditions and the main controlling factors for the enrichment of shale gas of Shanxi Formation in the southeast of Ordos Basin, China

Based on the dissection of the geological characteristics of typical shale gas wells, the relationship between reservoir-forming factors and shale gas enrichment is deeply analyzed, and the controlling factors of shale gas enrichment are summarized. An analysis of data from drilling, logging, testing, and shale sample has revealed that the factors contributing to the formation of shale gas reservoirs in marine–continental transitional facies of Shanxi Formation in the southeast of Ordos Basin are highly heterogeneous. This is mainly reflected in the rapid spatial change of shale organic matter, physical properties, and other parameters of the shale in this area. The shale found in the Shanxi Formation has a high content of organic carbon (TOC), with an average of 2.24%. The kerogen type is mainly type Ⅲ, and the average value of RO is 2.48%, indicating that it is in the high mature-overmature stage and is a high-quality source rock. The rock composition is rich in clay (40.5%–88.5%), mainly composed of illite-mongolian mixed layer and kaolinite, and its relatively high specific surface area is beneficial for improving the gas adsorption capacity of the shale. Thin sandstone interbeds, measuring less than 3 m are widely distributed in the Shanxi Formation and have good physical conditions. With an average porosity 3.37% and an average permeability of 0.1 mD. The natural gas generated by the shale can be transported to these sandstone interlayers (laminae) in a short distance, which is beneficial for improving the gas-bearing property of the shale. The gas-bearing property of the Shanxi Formation in the study area is affected by different lithologic assemblages. The gas-bearing property of the thick mudstone-coal assemblage of the second member of the Shanxi Formation is the best, with more than 80% of the samples having a gas content of over 1 m3/t. This study suggests that the high thermal evolution degree of shale, special marine–continental transitional facies reservoir conditions, and good preservation conditions are the main factors affecting the enrichment of shale gas in the study area. This makes the shale gas of the Shanxi Formation in the southeast of the Ordos Basin have certain potential for exploration and development, and delineates the enrichment targets of shale gas in the Zichang-Yan'an-Fuxian and Yichuan areas.

The source and formation characteristics of the Zhujiadun gas reservoirs in the Yancheng Sag, Subei Basin

The Yancheng Sag is a favorable exploration area in the Subei Basin. However, the key geological understanding of the natural gas source and reservoir formation characteristics of the sag is still controversial. Based on a set of organic geochemical experiments conducted on natural gas and associated condensate oil of the first member of the Funing Formation (E1f1) in well YCh5 and well data analysis, the oil-gas resources and reservoir formation model in the Zhujiadun gas reservoir in the Yancheng Sag, Subei Basin, were investigated. The results of this study are as follows. (1) The natural gas in the Zhujiadun gas reservoir is dry gas with high methane content, low heavy hydrocarbon content, and high maturity. The characteristics of carbon and hydrogen isotopes in the natural gas indicate that the natural gas is oil-cracked gas, which mainly originates from the source rocks of the Permian Qixia Formation. (2) The condensate oil from well YCh5 with a high degree of maturity has a high pristane/phytane ratio, low gamma-paraffin abundance, and low tricyclic terpene abundance, indicating a mixture of the Upper Paleozoic condensate oil and Cenozoic crude oil. The saturated and aromatic hydrocarbons have similar δ13C values to the Cenozoic continental crude oil. These features suggest two sources of condensate oil. (3) Oils generated from the source rocks of the Qixia Formation were cracked into highly mature gas after deep burial, which migrated along large faults into the sandstones of the E1f1 and K1t1 members. This type of reservoir was effectively preserved beneath the overlying mudstone cap rocks. Therefore, it can be inferred that a play fairway might occur in the eastern zone of the faults connected to the Paleozoic source rocks in the Yancheng Sag since this zone has similar petroleum geological conditions to well YCh5. Therefore, this zone is a favorable area for further exploration.

Key stage and model of hydrocarbon accumulation of Ordovician reservoir in Gucheng area, Tarim Basin, China

The heterogeneity of deep carbonate reservoirs is strong, it is significant for exploration and development to clarify the key stages of oil and gas accumulation. Taking the Ordovician in the Gucheng area of Tarim Basin as an example, this paper systematically investigated the key stage and model of hydrocarbon accumulation using the data of the cores, thin sections, cathode luminescence tests, laser ablation U-Pb isotope geochronometry, bitumen reflectance, and fluid inclusion tests, and seismic interpretation. (1) The Tarim Basin mainly develops three sets of effective source rocks, namely the Cambrian Yuertusi Formation, Cambrian Moheershan Formation, and Mid-Lower Ordovician Heituwa Formation, which are concentrated in the slope-basin facies of eastern Tarim Basin. (2) The Gucheng area is located in a favorable paleo-structural position. The pathway system composed of vertical faults and lateral unconformities occurs in the paleo-uplift, which is critical for hydrocarbon migration and accumulation. (3) The laser in-situ U-Pb dating, distribution and genesis of reservoir bitumen, burial-thermal maturation history, and the homogenization temperature of fluid inclusions suggest that the multi-stage tectonic thermal events of the Caledonian and Hercynian stages result in key adjustment and modification to deep hydrocarbon accumulation. Due to magmatic hydrothermal activities, the Caledonian primary oil reservoir massively evolved into oil-cracking gas reservoirs and residual paleo-oil reservoirs. (4) The paleo tectonic-fluid effect plays an important factor controlling the development of the Ordovician reservoirs. The evolution of the hydrocarbon accumulation in Gucheng area can be divided into three stages, namely formation of primary oil and gas reservoirs, oil-cracking gas reservoirs, and adjustment, destruction and reforming of gas reservoirs. To sum up, the western and northern parts of the paleo-uplift with favorable source-reservoir-cap rock assemblage and less effects of hydrothermal activities are the favorable zones for hydrocarbon exploration in the Gucheng area, the Tarim Basin.

Drilling-System Optimization Leads to Expedited Wells Delivery

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202172, “Drilling System Optimization Leads to Expedited Wells Delivery,” by Efe M. Ovwigho, SPE, Saleh Al Marri, and Abdulaziz Al Hajri, Schlumberger. The paper has not been peer reviewed. _ The authors write in the complete paper that simple changes in drillstring design can lead to huge savings in a climate requiring a constant push for reduction in well times and well costs and in improved well delivery. The complete paper explains the process that was followed before implementation of this solution. Introduction To access hydrocarbon reserves in a deep gas field, directional drilling through highly interbedded and abrasive formations was necessary. Designing a fit-for-purpose drilling system for optimal performance was critical. The reservoir drainage strategy required that the development wells be drilled directionally to attain a horizontal displacement of 1,500–2,500 ft at the 7-in. liner point above the gas reservoir formation. The well architecture was designed such that the well would be landed in the 8⅜-in. hole section. This required building inclination from vertical (0°) and landing the well at 80° inclination. Then, 4,000–5,000 ft of a 5⅞-in. hole lateral section would be drilled while holding 80° inclination or occasionally building to 90° inclination. Several initiatives had been implemented with the aim of optimizing drilling performance but had not experienced meaningful success in tackling vibration issues. Design Background An analysis of more than 100 horizontal wells drilled on the project revealed that 35% of total well time was consumed in the 8⅜-in. hole section. The majority of this time was spent on slow drilling or remedial operations. It was imperative that the proposed engineered drillstring meet the following requirements: - Able to drill through highly abrasive and interbedded formations - Maintain stability to avoid or reduce stick/slip, shocks, and vibration - Address surge and swab concerns - Minimize exposure through reduced handling - Optimize torque and drag - Optimized based on available tubulars on the rigsite - Reduce flat time Finite element analysis (FEA) and bottomhole assembly (BHA) modeling was performed with these requirements taken into consideration in a bid to generate a fit-for-purpose BHA (Fig. 1). In the deep gas field where the study was completed, the well had to be landed in the reservoir formation and maintain the 5⅞-in. lateral across the entire pay zone. A critical analysis of the formation determined that compressive strength exceeded 30,000 psi and that the formation was highly abrasive. A complete review of the drilling system was completed to optimize the approach to be taken.

North slope transition zone of Songnan-Baodao sag in Qiongdongnan Basin and its control on medium and large gas fields, South China Sea

Based on analysis of newly collected 3D seismic and drilled well data, the geological structure and fault system of Baodao sag have been systematically examined to figure out characteristics of the transition fault terrace belt and its control on the formation of natural gas reservoirs. The research results show that the Baodao sag has the northern fault terrace belt, central depression belt and southern slope belt developed, among them, the northern fault terrace belt consists of multiple transition fault terrace belts such as Baodao B, A and C from west to east which control the source rocks, traps, reservoirs, oil and gas migration and hydrocarbon enrichment in the Baodao sag. The activity of the main fault of the transition belt in the sedimentary period of Yacheng Formation in the Early Oligocene controlled the hydrocarbon generation kitchen and hydrocarbon generation potential. From west to east, getting closer to the provenance, the transition belt increased in activity strength, thickness of source rock and scale of delta, and had multiple hydrocarbon generation depressions developed. The main fault had local compression under the background of tension and torsion, giving rise to composite traps under the background of large nose structure, and the Baodao A and Baodao C traps to the east are larger than Baodao B trap. Multiple fault terraces controlled the material source input from the uplift area to form large delta sand bodies, and the synthetic transition belt of the west and middle sections and the gentle slope of the east section of the F12 fault in the Baodao A transition belt controlled the input of two major material sources, giving rise to a number of delta lobes in the west and east branches. The large structural ridge formed under the control of the main fault close to the hydrocarbon generation center allows efficient migration and accumulation of oil and gas. The combination mode and active time of the main faults matched well with the natural gas charging period, resulting in the hydrocarbon gas enrichment. Baodao A transition belt is adjacent to Baodao 27, 25 and 21 lows, where large braided river delta deposits supplied by Shenhu uplift provenance develop, and it is characterized by large structural ridges allowing high efficient hydrocarbon accumulation, parallel combination of main faults and early cessation of faulting activity, so it is a favorable area for hydrocarbon gas accumulation. Thick high-quality gas reservoirs have been revealed through drilling, leading to the discovery of the first large-scale gas field in Baodo 21-1 of Baodao sag. This discovery also confirms that the north transition zone of Songnan-Baodao sag has good reservoir forming conditions, and the transition fault terrace belt has great exploration potential eastward.

Characteristics, origin and controlling effects on hydrocarbon accumulation of overpressure in foreland thrust belt of southern margin of Junggar Basin, NW China

Aiming at the differential distribution of overpressure in vertical and lateral directions in the foreland thrust belt in the southern margin of Junggar Basin, the study on overpressure origin identification and overpressure evolution simulation is carried out. Based on the measured formation pressure, drilling fluid density and well logging data, overpressure origin identification and overpressure evolution simulation techniques are used to analyze the vertical and lateral distribution patterns of overpressure, genetic mechanisms of overpressure in different structural belts and causes of the differential distribution of overpressure, and the controlling effects of overpressure development and evolution on the formation and distribution of oil and gas reservoirs. The research shows that overpressure occurs in multiple formations vertically in the southern Junggar foreland thrust belt, the deeper the formation, the bigger the scale of the overpressure is. Laterally, overpressure is least developed in the mountain front belt, most developed in the fold anticline belt, and relatively developed in the slope belt. The differential distribution of overpressure is mainly controlled by the differences in disequilibrium compaction and tectonic compression strengths of different belts. The vertical overpressure transmission caused by faults connecting the deep overpressured system has an important contribution to the further increase of the overpressure strength in this area. The controlling effect of overpressure development and evolution on hydrocarbon accumulation and distribution shows in the following aspects: When the strong overpressure was formed before reservoir becoming tight overpressure maintains the physical properties of deep reservoirs to some extent, expanding the exploration depth of deep reservoirs; reservoirs below the overpressured mudstone cap rocks of the Paleogene Anjihaihe Formation and Lower Cretaceous Tugulu Group are main sites for oil and gas accumulation; under the background of overall overpressure, both overpressure strength too high or too low are not conducive to hydrocarbon enrichment and preservation, and the pressure coefficient between 1.6 and 2.1 is the best.

Formation conditions of Sinian–Cambrian large lithologic gas reservoirs in the north slope area of central Sichuan Basin, SW China

Based on analyses of characteristics, hydrocarbon charging history and geological conditions for the formation of Sinian–Cambrian reservoirs in the north slope area of central Sichuan paleo-uplift, the natural gas origin, accumulation evolution, accumulation pattern and formation conditions of large lithologic gas reservoirs have been investigated. Through comprehensive analyses of natural gas composition, carbon and hydrogen isotopic compositions, fluid inclusions, reservoir bitumen, and geological conditions such as lithofacies paleogeography and beach body characterization, it is concluded that: (1) The natural gas in the Sinian–Cambrian of the north slope area is mainly oil cracking gas, and different contribution ratios of multiple sets of source rocks lead to different geochemical characteristics of natural gas in different reservoirs. (2) Although the both Sinian and Cambrian gas reservoirs in this area are lithologic gas reservoirs under monocline background, the former has normal-pressure and the latter has high-pressure. There are three types of source-reservoir-caprock combinations: single source with lower generation and upper reservoir, double sources with lower generation and upper reservoir or with side source and lateral reservoir, double sources with lower generation and upper reservoir or with upper generation and lower reservoir. The Permian–Triassic is the main generation period of oil, Early–Middle Jurassic is the main generation period of oil cracking gas and wet gas, and Late Jurassic–Cretaceous is the main generation period of dry gas. (3) The Sinian–Cambrian system of the north slope area has two favorable conditions for formation of large lithologic gas reservoirs, one is that the large scale beach facies reservoirs are located in the range of ancient oil reservoirs or near the source rocks, which is conducive to the “in-situ” large-scale accumulation of cracked gas in the paleo-oil reservoirs, the other is that the large scale mound-beach complex reservoirs and sealing layers of inter beach tight zones match effectively to form large lithologic traps under the slope background. The research results confirm that the north slope area has large multi-layer lithologic gas reservoirs with more than one trillion cubic meters of natural gas resources and great exploration potential.

Helium enrichment mechanism of helium-rich gas reservoirs in central and western China: Degassing and accumulation from ancient groundwater

Helium, a coordinated resource in natural gas, is an essential and strategic resource, but research on its enrichment mechanism is relatively weak. This study investigated helium enrichment in major reservoirs in China using geochemical methods to address the challenging topic of how helium accumulates in helium-rich gas reservoirs. It concludes that helium is enriched in a few reservoirs which capture additional helium exsolution from ancient groundwater. Released dissolved helium from ancient groundwater into the reservoir is the main mechanism of helium accumulation in helium-rich gas reservoirs. This was the first time that the concept of “multiple sources of helium supply and primary sources of helium enrichment” was applied to guide the formation of helium-rich gas reservoirs. Moreover, the main sources of helium comes from the radioactive decay of uranium (U) and thorium (Th) in hydrocarbon rocks, reservoirs, and the decay of U and Th dissolved in groundwater from other rocks. When dissolved helium in ancient groundwater crosses free gas or gas reservoirs, the partial pressure of helium in the water is significantly higher than the partial pressure of helium in the free gas or gas reservoirs, proving Henry's Law which states that the helium in the water is almost completely exsolution into the gas reservoir, forming a helium-rich gas reservoir.

Dynamic reconstruction of the hydrocarbon generation, accumulation, and evolution history in ultra-deeply-buried strata

The evolution mechanism of hydrocarbons in ultra-deeply-buried and ultra-old strata is the core issue of petroleum geology moving towards Deep Earth. Reconstructing the evolutionary history of ultra-deeply-buried hydrocarbons is the key to shedding light on deep hydrocarbon accumulation and evolution mechanisms. Furthermore, it can help point out directions for oil and gas exploration in Deep Earth. Anyue gas field in the central Sichuan Basin is the Frontier of deep natural gas exploration in China. This study selected the natural gas reservoirs of the Upper Sinian Dengying Formation in the central Sichuan Basin as the research object. By integrating analysis of natural gas geochemical characteristics, source rock evaluation, reservoir bitumen-source correlation, inclusion analysis, one-dimensional and two-dimensional hydrocarbon accumulation simulations, the generation and evolution of hydrocarbons in different structural regions, namely the inherited paleo-uplift and slope area in central Sichuan Basin, have been dynamically restored and compared. The results show that: 1) The natural gas of the ultra-deeply-buried Sinian Dengying formation in central Sichuan is typical oil-cracking gas from the paleo-oil reservoir. The Sinian gas is mainly sourced from the Qiongzhusi/Maidiping Formation. 2) The formation of Sinian gas reservoirs includes three stages: the formation of paleo-oil-reservoirs; the cracking of paleo-oil-reservoirs into paleo-gas-reservoirs; the adjustment of the paleo-gas-reservoirs. 3) Source rock and reservoir evaluation, quantitative solid bitumen analysis, and hydrocarbon accumulation simulation show that the natural gas accumulation conditions in the slope area are better than in the inherited uplift area. The scale of the paleo-oil-reservoirs in the slope area may be greater than that in the inherited uplift area.

Superimposed hydrocarbon accumulation through multi-source and multi-stage evolution in the Cambrian Xixiangchi Group of eastern Sichuan Basin: A case study of the Pingqiao gas-bearing anticline

The Xixiangchi Group in eastern Sichuan Basin has great potential for natural gas exploration. However, there is a lack of in-depth studies of the hydrocarbon sources and the formation and evolution of gas reservoirs in this Group. Systematic investigation about the gas reservoir in Pingqiao anticline was consequently carried out in terms of characteristics of reservoir bitumen, the geochemical characteristics of natural gas, diagenetic minerals, and fluid inclusions. Based on this, combined with the reconstruction of the burial history, thermal evolution history and uplifting history of strata, and analysis of the regional tectonic settings, the hydrocarbon sources were identified and the formation and evolutionary processes of the gas reservoirs in Xixiangchi Group was revealed in this study. It was shown that the gas reservoirs have mixed gas sources from the shale source rocks in the Lower Cambrian Qiongzhusi Formation and in the Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation, and experienced several evolutionary stages, including the paleo-oil reservoir stage from the Late Siliurian to the Middle Permian, the paleo-gas reservoir stage from the Late Permian to the Early Cretaceous, and the superimposed accumulation and mixed-source gas reservoir stage since the Late Cretaceous. The mixed-source gas reservoir is formed by the adjustment of the Xixiangchi Group paleo-gas reservoirs and depressurization of the overpressure Wufeng-Longmaxi shale gas reservoirs and the charging of gas into the Xixiangchi Group reservoir of the Pingqiao anticline since the Late Cretaceous, which show obvious superimposed accumulation characteristics. There are different accumulation patterns in different geological periods. The accumulation pattern of the “old source - young reservoir” (i.e. hydrocarbons generated from older source rocks accumulating in younger reservoirs) dominates before the Late Cretaceous, and that of “juxtaposed young source - old reservoir” (i.e. hydrocarbons generated from younger source rocks accumulating in juxtaposed older reservoirs) dominates after the Early Cretaceous. Moreover, faults acted as critical vertical pathways for hydrocarbon migration during the evolution of the Xixiangchi Group gas reservoirs. This model provides new insights and theoretical basis for evaluation and mapping of the Xixiangchi Group play fairway in eastern Sichuan Basin.

Genesis and Accumulation Period of CO2 Gas Reservoir in Hailar Basin

Gas reservoirs with high CO2 have been found in several wells in the Hailar Basin. In this paper, a composition analysis, stable carbon isotope analysis, and a rare gas helium isotope 3He/4He and argon isotope 40Ar/36Ar analysis were carried out. These comprehensive analyses show that the CO2 in the Hailar Basin is inorganic-origin gas, which generally has the characteristics of crust–mantle-mixed CO2, and the fraction of helium of mantle source can reach 15.12~18.76%. There are various types of CO2 gas reservoirs. CO2 gas mainly comes from deep crust. The distribution of gas reservoirs is mainly controlled by deep faults and volcanic rocks, as well as by reservoir properties and preservation conditions. Magmatic rocks provide gas source conditions for the formation of inorganic CO2 reservoirs. Deep–large faults provide the main migration channels for CO2 gas. The sandy conglomerate and bedrock weathering crust of the Nantun Formation and the Tongbomiao Formation provide favorable reservoir spaces for the formation of CO2 gas reservoirs. The combination of volcanic rock mass and deep–large faults creates a favorable area for CO2 gas accumulation. The age of magmatic intrusion and the homogenization temperature of oil–gas inclusions in Dawsonite-bearing sandstone indicate that 120 Ma in the Early Cretaceous was the initial gas generation period of the CO2 reservoir and that oil and gas were injected into the reservoir in large quantities in 122~88 Ma. This period is the peak period of magmatic activity in Northeast China, as well as when the crust of Northeast China greatly changed. A large-scale CO2 injection period occurred in 100~80 Ma, slightly later than the large-scale injection period of the oil and gas. Since the Cenozoic, the structure has been reversed, and the gas reservoir has been adjusted.

A buried hill fault detection method based on 3D U-SegNet and transfer learning

Faults control the formation and development of fault-block buried hill oil and gas reservoirs. Therefore, if the fault can be accurately detected, the well location can be accurately deployed, which is beneficial to improving recovery efficiency and production. Conventional convolutional neural networks (CNNs) have difficulty obtaining a large number of real fault samples. These approaches usually train on artificially synthesized samples, bringing about challenge for accurate prediction of different faults, especially for buried hill faults. To address it, we propose a detection method for buried hill faults based on a 3D hybrid network U-SegNet combined with transfer learning. First, we construct two traditional semantic segmentation networks, i.e., U-Net and SegNet, to form a new 3D U-SegNet network. Next, we train this network using plenty of 3D synthetic seismic data. Finally, we implement transfer learning by model fine-tuning using a few labeled real data. The method is applied to the buried hill field data, and the result proves that the U-SegNet network, after transfer learning, can reduce the cases of fault miss and false detection and can effectively improve the accuracy, which verifies the value of this research for complicated buried hill fault detection.

Analysis of factors influencing recovery of low permeability and strong heterogeneous gas reservoirs and establishment of prediction model

Jialingjiang Formation is a typical low permeability carbonate reservoir in Sichuan Basin, which is characterized by strong heterogeneity, low matrix permeability and high-water saturation. Based on seven influencing factors, such as permeability, reservoir thickness and reservoir porosity, this paper evaluates and predicts the oil recovery of Jialingjiang Formation gas reservoir by using two neural network models of multilayer perceptor and radial basis function and nonlinear surface fitting method. The results show that: 1) In the neural network prediction model, the correlation coefficient between the prediction result curve of multilayer perceptron and the original recovery curve reaches 0.88, which is higher than the radial basis function (0.81), indicating that the use of multilayer perceptron can better predict the recovery of gas reservoirs. 2) In the nonlinear curved surface fitting prediction model, the two influencing factors with the greatest linear correlation with the recovery factor, reservoir thickness and gas recovery rate, are selected to fit the prediction model, and the prediction model is obtained. According to the prediction model, the recovery factor is positively correlated with the reservoir thickness and gas recovery rate on the whole. The model can be used to estimate gas recovery from two factors: reservoir thickness and gas recovery rate.

Fluid evolution and hydrocarbon accumulation model of ultra-deep gas reservoirs in Permian Qixia Formation of northwest Sichuan Basin, SW China

The fluid evolution and reservoir formation model of the ultra-deep gas reservoirs in the Permian Qixia Formation of the northwestern Sichuan Basin are investigated by using thin section, cathodoluminescence, inclusion temperature and U-Pb isotopic dating, combined with gas source identification plates and reservoir formation evolution profiles established based on burial history, thermal history, reservoir formation history and diagenetic evolution sequence. The fluid evolution of the marine ultra-deep gas reservoirs in the Qixia Formation has undergone two stages of dolomitization and one phase of hydrothermal action, two stages of oil and gas charging and two stages of associated burial dissolution. The diagenetic fluids include ancient seawater, atmospheric freshwater, deep hydrothermal fluid and hydrocarbon fluids. The two stages of hydrocarbon charging happened in the Late Triassic and Late Jurassic–Early Cretaceous respectively, and the Middle to Late Cretaceous is the period when the crude oil cracked massively into gas. The gas reservoirs in deep marine Permian strata of northwest Sichuan feature multiple source rocks, composite transportation, differential accumulation and late finalization. The natural gas in the Permian is mainly cracked gas from Permian marine mixed hydrocarbon source rocks, with cracked gas from crude oil in the deeper Sinian strata in local parts. The scale development of paleo-hydrocarbon reservoirs and the stable and good preservation conditions are the keys to the forming large-scale gas reservoirs.

Genetic Type and Source Analysis of Natural Gas in the Leikoupo Formation of the Sichuan Basin in China

The Middle Triassic Leikoupo Formation is largely extended through the Sichuan Basin, SW China. In this formation, several commercially exploited gas reservoirs have been discovered in western and central parts of the basin. Due to the complicated geochemical signatures of the natural gases in these reservoirs, there are contrasted interpretations about their sources, which hamper the evaluation and exploration for new gas resources in the area. To obtain complete understanding of the natural gas sources, the Leikoupo Formation gas reservoirs discovered so far in the Zhongba, Yuanba, Longgang, and Moxi gas fields were selected as the research object of this study. The genetic types and sources of the natural gases in the Leikoupo Formation are discussed based on gas geochemistry combined with their geological background. The natural gas in the top members of the Leikoupo Formation (T2l4 or T2l3) is partially originated from a humic kerogen contained in the source rocks from the overlying Upper Triassic Xujiahe Formation and from sapropel kerogen from the source rocks of the Leikoupo Formation itself. The natural gas of T2l1 member in the lower part of the Leikoupo Formation is mainly sapropel-type probably from the source rock of the Permian Wujiaping Formation, where the Permian Longtan Formation undergoes a phase change into the Wujiaping Formation The reversed δ13C1 and δ13C2 trend in the Leikoupo Formation of the Yuanba gas field is due to the more sapropelic source rocks and higher degree of maturity.

Differential Reservoir-Forming Mechanisms of the Lower Paleozoic Wufeng-Longmaxi and Niutitang Marine Gas Shales in Northern Guizhou Province, SW China: Theories and Models

Fine dissection of microscopic pore structure variations between the Niutitang Formation and the Wufeng-Longmaxi Formation will help to improve the understanding of the underlying geological theory of shale gas in northern Guizhou Province. The stratigraphic, geochemical, physical, and tectonic properties of the two formations vary greatly, resulting in differential development of the microscopic pore structure among reservoirs and, as a result, major variances in gas concentration. To explore the mechanism of differential pore evolution, experimental techniques and instruments such as gas adsorption, liquid intrusion, SEM, XRD, and organic geochemical tests were utilized. The results indicate that the Wufeng-Longmaxi Formation is in a high-maturity stage, while the Niutitang Formation is in an over-mature stage. The latter has a higher TOC content. Both petrographic phases are siliceous shale petrographic phases, and the former has more developed dissolution pores with better pore volume, throat radius, and macropore pore diameters than the latter, as well as organic matter pores, intergranular pores, and microfracture structural parameters, whereas the specific surface area is the opposite. The differences in reservoir pore formation between the two formations were analyzed, and the results showed that the petrographic type, thermal evolution, and tectonic preservation conditions were the primary controlling elements of differential shale gas reservoir formation. A differential reservoir-forming model of the Wufeng-Longmaxi Formation and the Niutitang Formation was constructed, providing a geological and theoretical basis for shale gas geological exploration in northern Guizhou Province.

Case Study of Successfully Staged Acid Fracturing on the Ultra-Deep Horizontal Well for the Qixia Fm HTHP Tight Carbonate Gas Reservoir in China

The lower Permian Qixia formation gas reservoir is characterized by ultra-deep buried, high temperature and high pressure (HTHP), low porosity and permeability, ultra-high closure pressure, and thin thickness in the western Sichuan Basin, China. Acid fracturing has been adopted as the main well stimulation technology. The average test production of the acid-fractured vertical well was 46 × 104 m3/d. The horizontal well with staged acid fracturing is considered a reliable measure to enhance gas production. However, the staged acid fracturing on the ultra-deep horizontal well has been challenged. The reaction rates of conventional, self-diverting, and gelled acid and the acid-etched fracture conductivity experiments under HTHP are measured to optimize the acid fracturing technique. The reaction rate of gelled acid with Qixia Fm limy dolomite at 150°C is 3.4–6.7 times faster than that with dolomite and similar to that with limestone. The gelled acid with better retardation and friction reduction performance is selected as the main acid to increase the effective acid-etched fracture length. The acid-etched fracture conductivity can be greatly enhanced by using gelled acid, increasing acid volume, and closed fracture acidizing (CFA) under a closure stress of 50 MPa. Moreover, the feasibility of staged acid fracturing for ultra-deep horizontal wells is discussed. The first stage is assembled by fracturing sleeve, spared ball drop sleeve, and circulating valve to ensure activation of the fracturing channel. The tested production is significantly enhanced with temporary plugging and open-hole packer and sliding sleeve staged acid fracturing.

The Thermal Effect of Submarine Mud Volcano Fluid and Its Influence on the Occurrence of Gas Hydrates

Mud volcanoes and other fluid seepage pathways usually transport sufficient gas for the formation of gas reservoirs and are beneficial to the accumulation of gas hydrate. On the other hand, the fluid thermal effects of mud volcanoes can constrain the occurrence of gas hydrates. Current field measurements indicate that fluid thermal anomalies impact the distribution of gas hydrates associated with mud volcanoes. However, due to the lack of quantitative analysis of the mud volcano fluid flow and thermal evolution, it is difficult to effectively reveal the occurrence of gas hydrates in mud volcano development areas and estimate their resource potential. This study took the Håkon Mosby Mud Volcano (HMMV) in the southwestern Barents Sea as the research object and comprehensively used seismic, well logging, drilling and heat flow survey data, combining the principles and methods of fluid dynamics and thermodynamics to study the fluid flow and heat transfer of a mud volcanic pathway. The space framework of the mud volcanic fluid temperature field thermal structure was established, the influence of the HMMV fluid thermal effect on gas hydrate occurrence was analyzed and the distribution and resource potential of gas hydrates in mud volcano development areas were revealed from the perspective of thermodynamics. This study provides a thermodynamic theoretical basis for gas hydrate accumulation research, exploration and exploitation under a fluid seepage tectonic environment.