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The ebb and flow of Chinese petroleum : a story told by a witness
\"For the first time, a work that breaks with the official Chinese government narrative concerning the petroleum industry and provides the true story as personally experienced by the author, Mao Huahe, a thirty-year veteran and executive in the oil industry. Mao witnessed first-hand the breakthrough discovery of the Daqing Oilfield, the behind-the-scenes political machinations and turmoil of the Cultural Revolution and the subsequent reform and opening period, and details the effects these events had upon China's petroleum industry\"-- Provided by publisher.
Book
The Ebb and Flow of Chinese Petroleum
In The Ebb and Flow of Chinese Petroleum, the author Huahe Mao breaks with the official government narrative concerning the Chinese petroleum industry and provides the true story as he personally experienced it.
eBook
Characteristics of inclusions in chang 7 member and shale oil accumulation stages in Zhijing-Ansai area, Ordos Basin
In order to further clarify the shale oil accumulation period of the Chang 7 member of the Mesozoic Triassic Yanchang Formation in the Zhijing-Ansai area of the central Ordos Basin, Using fluid inclusion petrography analysis, microscopic temperature measurement, salinity analysis and fluorescence spectrum analysis methods, combined with the burial history-thermal history recovery in the area, the oil and gas accumulation period of the Chang 7 member of the Yanchang Formation in the Zhijing-Ansai area was comprehensively analyzed. Sixteen shale oil reservoir samples of the Mesozoic Triassic Yanchang Formation in seven typical wells in the study area were selected.The results show that the fluid inclusions in the Chang 7 member of Yanchang Formation can be divided into two stages. The first stage inclusions mainly develop liquid hydrocarbon inclusions and a large number of associated brine inclusions, which are mainly beaded in fracture-filled quartz and fracture-filled calcite. The fluorescence color is blue and blue-green, and the homogenization temperature of the associated brine inclusions is between 90–110°C. The second stage inclusions are mainly gas-liquid two-phase hydrocarbon inclusions, gas inclusions and asphalt inclusions. Most of them are distributed in the fracture-filled quartz, and the temperature of the associated brine inclusions is between 120–130°C. Fluid inclusions in Chang 7 member of the Yanchang Formation can be divided into two stages. The CO 2 inclusions and high temperature inclusions in the Chang 7 member of the Yanchang Formation are mainly derived from deep volcanic activity in the crust.
Journal Article
Description of the reservoir along strike-slip fault zones in China T-Sh oilfield, Tarim Basin
The reservoir depth of T-Sh oilfield in Tarim Basin is more than 7500 m, which is a typical deep carbonate fault-controlled reservoir. The S-1 and S-5 fault zones experienced multi-stage tectonic movements and developed complex fault-fracture systems. Based on geometry and dynamics, the evolution characteristics of faults are analyzed; the permeability of strike-slip faults in the middle and lower Ordovician carbonate strata drilled through in S-5 fault zone is studied by comprehensively using core observation, imaging logging, 3D seismic data, and drilling historical data, taking wells F-1 and F-10 as examples. It is found that the fault-fracture system is the main reservoir space and fluid migration channel in the reservoir. A large mud loss will occur when drilling high permeability faults. High production can be obtained after conventional well completion, otherwise, it is difficult to get production. In this paper, slip tendency coefficient is used to quantitatively characterize the permeability of fractures in T-SH ultra-deep reservoir. Based on the one-dimensional geomechanical model and three-dimensional geological structure model of typical wells, the slip tendency coefficients of different parts of the fault-fracture system are calculated using finite element numerical simulation method. Compared with the historical data of drilling in S-1 and S-5 fault zones, it is found that the slip tendency coefficient is positively correlated with mud loss. The results show that the critical slip tendency coefficient of the S-5 fault zone is 0.3, and that of the S-1 fault zone is 0.2. This study provides a new idea and method for the prediction of geological desserts and well trajectory design in the T-Sh reservoir.
Journal Article
Multi-stage gas diffusion and its implications for the productivity of coalbed methane in the southern Qinshui Basin, north China
The behavior of coalbed methane (CBM) diffusion considerably influences gas productivity. Based on the multi-porous diffusion model and on-site CBM desorption data of coal cores, the behavior of CBM diffusion and its implications on the gas productivity of No. 3 coal seam in the southern Qinshui Basin (SQB) were elaborately analyzed. Results indicate that CBM diffusion of No. 3 coal seam demonstrates noticeable three-stage characteristics, including the fast diffusion, transitional diffusion, and slow diffusion stages. During the gas diffusion process, the gas content and/or the degree of developed pores and fractures/cleats in coal seams can affect the desorption of CBM and the amount of diffused CBM by influencing the changes in gas pressure in pores, thus controlling the behavior of gas diffusion in different stages. Because gas content and the developed degree of pores and fractures/cleats are closely associated with the deformation degree of the coal seams, variably deformed coal seams exhibit unique characteristics of gas diffusion. The low-deformation degree of the coal seams have a relatively uniform distribution of gas production over the history of a well. By contrast, the moderate-deformation degree of the coal seams have a relatively high rate and amount of gas diffusion in the fast and transitional diffusion stages, producing most of the gas in the early-to-intermediate stages of the wells. Finally, the high-deformation degree of the coal seams has a high rate and amount in the fast diffusion stage, indicating that most of the production stage occurs during the early stage of the gas production history of a well. In summary, the behavior of gas diffusion can be used for predicting gas production potential.
Journal Article
Quantitative reconstruction of formation paleo-pressure in sedimentary basins and case studies
Paleo-pressure reconstruction in sedimentary basins is one of the most important aspects of hydrocarbon accumulation research. In view of the advantages and disadvantages of the current methods for paleo-pressure research, a new method to reconstruct the paleo-pressure is presented in this paper. According to the geological background, quantitative analyses of the factors that might control overpressure were first conducted to clarify the contributions of each mechanism during different geological periods. Pressure evolution was reconstructed by fluid-compaction modelling with constraints imposed by the paleo-pressures obtained from fluid inclusions or differential stress methods. Determining the mechanisms responsible for overpressures during geological history is the basic prerequisite for paleo-pressure research. Thus, quantitative studies were conducted of the contributions of disequilibrium compaction, gas charging, oil cracking, temperature reduction, and tectonic uplift and subsidence to overpressures. Three case studies of paleo-pressure reconstruction were performed for the Sinian strata in the Sichuan Basin, Ordovician strata in the north uplift in the Tarim Basin and the Permian strata in the Sulige Gas Field in the Ordos Basin, where these three study sites are normally pressured, weakly over-pressured and abnormally low pressured at present, respectively. The new method developed in this paper is very important for the practical reconstruction of the paleo-pressure in marine strata and ancient strata in deep basins.
Journal Article
Fast History Matching and Flow Channel Identification for Polymer Flooding Reservoir with a Physics-Based Data-Driven Model
The offshore reservoir development involves large injection and production rates and high injection pressures. High-permeability flow channels usually occur in offshore unconsolidated heavy-oil reservoirs during long-term water flux, substantially impacting the production performance. As one important method for identifying channeling, the numerical simulation method with a full-fidelity model is hampered by the low computational efficiency of the history matching process. The GPSNet model is extended for polymer flooding simulations, incorporating complex mechanisms including adsorption and shear-thinning effects, with solutions obtained through a fully implicit numerical scheme. Four flow channel characteristic parameters are proposed, and an evaluation factor M for flow channel identification is established with the comprehensive evaluation method. Finally, the field application of the GPSNet model is made and validated by the tracer interpretation result. The history matching speed based on the GPSNet model is 58 times faster than the full-fidelity ECLIPSE model. In addition, the application demonstrates a high degree of consistency with tracer monitoring results, confirming the accuracy and field feasibility. The new method enables rapid and accurate identification and prediction of large and dominant channels, offering effective guidance for targeted treatment of channels and sustainable development of polymer flooding.
Journal Article
Integrated Simulation for Microseismic Fracture Networks with Automatic History Matching in Tight Oil Development: A Field Case from Block Y2 in Ordos Basin, China
The reliability of forecasts, fracture design, and recovery enhancement strategies in tight oil reservoirs is significantly compromised by the substantial uncertainties associated with fracture characterization. This article introduces an integrated simulation workflow for modeling microseismic fracture networks in tight oil reservoirs, incorporating automatic history matching, as illustrated through a field case study from block Y2 in the Ordos Basin, China. The model stochastically generates the geometry of complex fracture networks (CFNs), including parameters such as length, aperture, inclination and azimuth angles, and spatial positioning, constrained by data from hydraulic fracturing, core analyses, and microseismic monitoring. It employs a stochastic parameterization model to produce an ensemble of initial CFN property realizations and utilizes an advanced Green function-based hierarchical fracture model to accurately depict CFN morphology. The model is further refined, and its uncertainty in fracture characterization is minimized through calibration with an innovative Ensemble Kalman Filter-based assisted history-matching algorithm. Evidence suggests that this comprehensive approach effectively leverages all available geological data, substantially reduces uncertainties in the production process, and aids in identifying the optimal development strategy.
Journal Article
Present-Day Geothermal Regime and Thermal Evolution of the Fukang Sag in the Junggar Basin, Northwest China
The Fukang Sag in the Junggar Basin is an important petroleum exploration and exploitation region. However, the geothermal regime and tectono-thermal evolution of the Fukang Sag, which control its hydrocarbon generation and conservation, are still controversial. This study involved a systematic analysis of the present-day geothermal gradient, heat flow, and thermal history of the Fukang Sag for better further exploration. According to the well log data and well-testing temperature data, we calculated that the geothermal gradient of the Fukang Sag ranges from 16.6 °C/km to 29.6 °C/km, with an average of 20.8 °C/km, and the heat flow ranges from 34.6 mWm−2 to 64.3 mWm−2, with an average of 44.6 mWm−2. Due to the basement relief, they decrease from northeast to southwest. The weight averages of the single-grain apatite (U-Th)/He ages of the core samples are 1.3–85.2 Ma, and their apatite fission track ages range from 50.9 Ma to 193.8 Ma. The thermal modeling results revealed that the Fukang Sag experienced late Permian, late Jurassic, and late Cretaceous cooling events (although the timing and magnitude of these events varied among the samples), which were related to the continuous compression of the Junggar Basin. In addition, basin modeling indicated that the heat flow of the Fukang Sag decreased from 80 mWm−2 in the Carboniferous to the current value of 44.6 mWm−2. The Fukang Sag’s edge exhibits prolific hydrocarbon generation in the Carboniferous–Permian source rocks, while the Jurassic source rocks within the sag also undergo abundant hydrocarbon generation. This study provides new insights into the present-day geothermal field and tectono-thermal evolutionary history of the Fukang Sag, which are significant in terms of regional tectonic evolution and oil and gas resource assessment.
Journal Article
Pore Preservation and Failure Mechanism of Sinian Dengying Formation Carbonate Reservoirs: A Case Study of Two Ultradeep Wells in the Sichuan Basin, Western China
Despite being one of the most important factors in deep oil and gas exploration, the preservation mechanisms of ultradeep carbonate reservoirs remain poorly understood. This study performed thin-section, geochemistry, field emission scanning electron microscopy, fluid inclusion, and basin model analysis of samples from two boreholes over 8,000 m deep in the Sichuan Basin to determine the pore features and preservation mechanism of the Sinian (Ediacaran) Dengying Formation carbonate reservoirs. The reservoir of CS well #1 is characterised by pore diameters larger than a centimetre (average porosity 7.48%; permeability 0.8562 mD), and the pores are mainly filled with dolomite or bitumen. In contrast, the reservoir of MS well #1 is predominantly composed of micron-scale residual pores (average porosity 1.74%; permeability 0.0072 mD), and the pores are typically filled with dolomite, bitumen, and multistage quartz. The burial thermal histories suggest that both reservoirs were subjected to high pressure (i.e., pressure coefficient>1.5) before the Late Cretaceous. However, the pressure coefficient of the reservoir of MS well #1 has decreased to less than 1.0 owing to strong structural adjustment this well since the Late Cretaceous, which allowed other ore-forming fluids to enter and fill the pores, resulting in further compaction of the pores. In contrast, the pressure coefficient of CS well #1 is 1.1–1.2, which effectively prevented other ore-forming fluids from entering and filling the pores. The findings show that the dynamic adjustment of the Dengying Formation palaeo-gas reservoir indirectly affects the preservation or failure of the reservoir. The occurrence and geometry of bitumen in the Dengying reservoir exhibit good consistency with the pressure changes in both boreholes. In particular, bitumen with an annular shape and contraction joints in reservoir pores is widespread in CS well #1, which is attributed to the continuous preservation of palaeo-gas fields. Conversely, bitumen with a broken particle shape is located among the epigenetic minerals widespread in MS well #1, which is attributed to failure and depletion of the palaeo-gas fields.
Journal Article