Interaction of coal and oil in confined pyrolysis experiments: Insight from the yield and composition of gas hydrocarbons

Isothermal pyrolysis experiments were performed for coal alone, oil alone and coal plus oil with oil/coal ratios ranging from 0.0065 to 0.1995 at 305 °C and 50 MPa for 72 h in confined systems (gold capsules). The results of these experiments reveal the interaction between coal and oil, demonstrating that oil retards the generation of gas hydrocarbons from coal cracking while coal accelerates oil cracking into gas hydrocarbons. The yields of gas hydrocarbons vary greater with oil/coal ratio in the experiments of coal B plus oil than coal A plus oil because coal A has a higher HI value than does coal B. Oil cracking rate could increase by up to 10 or even higher times in the experiments of coal plus oil compared with oil alone, deduced from the yields and chemical compositions of gas hydrocarbons. This result suggests that gas hydrocarbons, especially wet gases were largely generated from the cracking of oil or extractable bitumen in the experiments of coal plus oil with oil/coal ratio higher than 0.1.     

Flow-type apparatus for studying thermotolerance of hyperthermophiles under conditions simulating hydrothermal vent circulation

A flow-type apparatus has been developed to study thermotolerance of microorganisms under conditions simulating submarine hydrothermal circulation. The apparatus is designed so that microorganisms can be exposed to high temperature for periods of only a few seconds duration, and can be operated at temperatures up to 400 °C and hydrostatic pressures up to 30 MPa, even under strict anaerobic conditions. The performance of the apparatus was tested by studying the thermotolerance of a mesophilic bacterium, Escherichia coli strain W3110, after heat treatment at temperatures between 59.0 and 64.5 °C for 1.5 s. The results compared favorably with the literature data obtained by a conventional batch method at lower temperatures and longer heating durations. Thermotolerance of a hyperthermophilic archaeon, Pyrococcus horikoshii strain OT3, was successfully determined by the apparatus at temperatures up to 119 °C and pressures up to 25 MPa under anaerobic conditions.     

Numerical study of multi-period palaeotectonic stress fields in Lower Cambrian shale reservoirs and the prediction of fractures distribution: A case study of the Niutitang Formation in Feng'gang No. 3 block,South China

Fractures not only control the distribution of oil and gas reservoirs, but also are key points in the research of oil and gas reservoir development programmes. The tectonic fractures in the Lower Cambrian shale reservoirs in the Feng'gang No. 3 block are effective reservoir spaces for hydrocarbon accumulation, and these fractures are controlled by palaeotectonic stress fields. Therefore, quantitatively predicting the development and distribution of tectonic fractures in the Lower Cambrian shale reservoir is important for the exploration and exploitation of shale gas in the Feng'gang No. 3 block. In the present study, a reasonable geological, mechanical and mathematical model of the study area was established based on the faults systems interpreted from seismic data, fracture characteristics from drilling data, uniaxial and triaxial compression tests and experiments on the acoustic emissions (AE) of rocks. Then, a three-dimensional (3-D) finite element method is applied to simulate the palaeotectonic stress field with the superposition of the Yanshan and Himalayan movements and used to predict the fracture distribution. The simulation results indicate that the maximum principal stress value within the study area ranged from 269.97 MPa to 281.18 MPa, the minimum principal stress ranged from 58.29 MPa to 79.64 MPa, and the shear stress value ranged from 91.05 MPa to 106.21 MPa. The palaeotectonic stress field is controlled by the fault zone locations. The fracture development zones are mainly controlled by the tectonic stress fields and are located around the faults, at the end of the fault zones, at the inflection point and at the intersection of the fault zones.     

Novel 3D centimetre-to nano-scale quantification of an organic-rich mudstone: The Carboniferous Bowland Shale,Northern England

X-ray computed tomography and serial block face scanning electron microscopy imaging techniques were used to produce 3D images with a resolution spanning three orders of magnitude from ∼7.7 μm to 7 nm for one typical Bowland Shale sample from Northern England, identified as the largest potential shale gas reservoir in the UK. These images were used to quantitatively assess the size, geometry and connectivity of pores and organic matter. The data revealed four types of porosity: intra-organic pores, organic interface pores, intra- and inter-mineral pores. Pore sizes are bimodal, with peaks at 0.2 μm and 0.04 μm corresponding to pores located at organic–mineral interfaces and within organic matter, respectively. These pore-size distributions were validated by nitrogen adsorption data. The multi-scale imaging of the four pore types shows that there is no connected visible porosity at these scales with equivalent diameter of 20 nm or larger in this sample. However, organic matter and clay minerals are connected and so the meso porosity (<20 nm) within these phases provides possible diffusion transport pathways for gas. This work confirms multi-scale 3D imaging as a powerful quantification method for shale reservoir characterisation allowing the representative volumes of pores, organic and mineral phases to be defined to model shale systems. The absence of connected porosity at scales greater than 20 nm indicates the likely importance of the organic matter network, and associated smaller-scale pores, in controlling hydrocarbon transport. . The application of these techniques to shale gas plays more widely should lead to a greater understanding of properties in the low permeability systems.     

Features and sealing mechanism of shallow biogenic gas in incised valley fills (the Qiantang River,eastern China): A case study

Late Quaternary shallow biogenic gas reservoirs have been discovered and exploited in the Qiantang River (QR) estuary area, eastern China. The fall of global sea level during the Last Glacial Maximum resulted in the formation of the QR incised valley. From bottom to top, the incised valley successions can be grouped into four sedimentary facies: river channel facies, floodplain–estuarine facies, estuarine-shallow marine facies, and estuarine sand bar facies.All commercial biogenic gas pools occur in floodplain–estuarine sand bodies of the QR incised valley and its branches. The deeply incised valleys provided favorable conditions for the generation and accumulation of shallow biogenic gas.The clay beds that serve as the direct cap beds of the gas pools are mostly restricted within the QR incised valley, with burial depths ranging from 30 to 80 m, remnant thicknesses of 10–30 m, and porosities of 42.2–62.6%. In contrast, the mud beds cover the whole incised valley and occur as indirect cap beds, with burial depths varying from 5 to 35 m, thicknesses of 10–20 m, and porosities of 50.6–53.9%. The pore-water pressures of clay and mud beds are higher than that of sand bodies, and the difference can be as much as 0.48 MPa. The pore-water pressures of clay or mud beds can exceed the total pore-water pressure and gas pressure of underlying sand reservoirs. Shallow biogenic gas can be completely sealed by the clay and mud beds, which have higher pore-water pressure. The direct cap beds have better sealing ability than the indirect cap beds.Generally, the pore-water pressure dissipation time of clay and mud beds is conspicuously longer than that of sand beds. This indicates that the clay and mud beds have worse permeability and better sealing ability than the sand beds. However, once the gas enters the sand lenses, the pore-water pressure cannot release efficiently.     

Petroleum source rock potential of the Silurian Dadaş shales in the Hazro and Korudağ regions of Southeast Anatolia,Turkey

Shales of the Silurian Dadaş Formation exposed in the southeast Anatolia were investigated by organic geochemical methods. The TOC contents range from 0.24 to 1.48 wt% for the Hazro samples and 0.19 to 3.58 wt% for the Korudağ samples. Tmax values between 438 and 440 °C in the Hazro samples indicate thermal maturity; Tmax values ranging from 456 to 541 °C in the Korudağ samples indicate late to over-maturity. Based on the calculated vitrinite reflectance and measured vitrinite equivalent reflectance values, the Korudağ samples have a maximum of 1.91%R_(g-v), in the gas generation window, while a maximum value of 0.79%R_(amor-v) of one sample from the Hazro section is in the oil generation window. Illite crystallinity (IC) values of all samples are consistent with maturity results.Pr/Ph ratios ranging from 1.32 to 2.28 and C₂₉/C₃₀ hopane ratios > 1.0 indicate an anoxic to sub-oxic marine-carbonate depositional environment.The Hazro shales do not have any shale oil or shale gas potential because of their low oil saturation index values and early to moderate thermal maturation. At first glance, the Korudağ shales can be considered a shale gas formation because of their organic richness, thickness and thermal over-maturity. However, the low silica content and brittle index values of these shales are preventing their suitability as shale gas resource systems.     

Experimental study on mechanical properties of gas hydrate-bearing sediments using kaolin clay

A triaxial system is designed with a temperature range from-20 ℃ to 25 ℃ and a pressure range from 0 MPa to 30 MPa in order to improve the understanding of the mechanical properties of gas hydrate-bearing sediments.The mechanical properties of synthetic gas hydrate-bearing sediments (gas hydrate-kaolin clay mixture) were measured by using current experimental apparatus.The results indicate that:(1) the failure strength of gas hydrate-bearing sediments strongly depends on the temperature.The sediment’s strength increases with the decreases of temperature.(2) The maximum deviator stress increases linearly with the confining pressure at a low-pressure stage.However,it fluctuates at a high-pressure stage.(3) Maximum deviator stress increases with increasing strain rate,whereas the strain-stress curve has no tremendous change until the axial strain reaches approximately 0.5%.(4) The internal friction angles of gas hydrate-bearing sediments are not sensitive to kaolin volume ratio.The cohesion shows a high kaolin volume ratio dependency.     

A laboratory study on capillary sealing efficiency of Iranian shale and anhydrite caprocks

Caprock has the most important role in the long term safety of formation gas storage. The caprocks trap fluid accumulated beneath, contribute to lateral migration of this fluid and impede its upward migration. The rapid upward passage of invasive plumes due to buoyancy pressure is prevented by capillary pressure within these seal rocks. In the present study, two main seal rocks, from the Zagros basin in the southwest of Iran, a shale core sample of Asmari formation and an anhydrite core sample of Gachsaran formation, were provided. Absolute permeabilities of shale and anhydrite cores, considering the Klinkenberg effect, were measured as 6.09 × 10⁻¹⁸ and 0.89 × 10⁻¹⁸ m², respectively. Capillary sealing efficiency of the cores was investigated using gas breakthrough experiments. To do so, two distinct techniques including step by step and residual capillary pressure approaches were performed, using carbon dioxide, nitrogen and methane gases at temperatures of 70 and 90 °C, under confining pressures in the range 24.13–37.92 MPa. In the first technique, it was found that capillary breakthrough pressure of the cores varies in the range from 2.76 to 34.34 MPa. Moreover, the measurements indicated that after capillary breakthrough, gas effective permeabilities lie in range 1.85 × 10⁻²¹ – 1.66 × 10⁻¹⁹ m². In the second technique, the minimum capillary displacement pressure of shale varied from 0.66 to 1.45 MPa with the maximum effective permeability around 7.76 × 10⁻²¹ – 6.69 × 10⁻²⁰ m². The results indicate that anhydrite caprock of the Gachsaran formation provides proper capillary sealing efficacy, suitable for long term storage of the injected CO₂ plumes, due to its higher capillary breakthrough pressure and lower gas effective permeability.     

High pressure-high temperature laboratory apparatus for the measurement of deep sea sediment physical properties

Laboratory equipment has been built which will measure the permeability and thermal conductivity of deep-sea sediments at their in-situ conditions of hydrostatic pressure, temperature, and void ratio. The apparatus has the capability of uniaxially consolidating a sediment sample to simulate compaction within the sediment column, while exposing the specimen to hydrostatic pressures ranging from atmospheric to 62 MPa and to temperatures from 22 to 220°C. The equipment includes a hypodermic needle mounted vertically through the base of the pressure vessel from which thermal conductivity is determined by the needle probe method. The system also features a combination of dead-weight testers which produces a small hydraulic gradient across the sample and permits the measurement of sediment permeability at large hydrostatic pressures.The physical property data generated from this apparatus will be important in understanding the mechanisms of heat transfer through the ocean floor and in analysing the coupled flow of heat and pore fluid in the vicinity of a heat source, such as a radioactive waste canister, buried in the seabed.     

Gas geochemistry of the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Implications for gas hydrate exploration in the Arctic

Gases were analyzed from well cuttings, core, gas hydrate, and formation tests at the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well, drilled within the Milne Point Unit, Alaska North Slope. The well penetrated a portion of the Eileen gas hydrate deposit, which overlies the more deeply buried Prudhoe Bay, Milne Point, West Sak, and Kuparuk River oil fields. Gas sources in the upper 200 m are predominantly from microbial sources (C₁ isotopic compositions ranging from −86.4 to −80.6‰). The C₁ isotopic composition becomes progressively enriched from 200 m to the top of the gas hydrate-bearing sands at 600 m. The tested gas hydrates occur in two primary intervals, units D and C, between 614.0 m and 664.7 m, containing a total of 29.3 m of gas hydrate-bearing sands. The hydrocarbon gases in cuttings and core samples from 604 to 914 m are composed of methane with very little ethane. The isotopic composition of the methane carbon ranges from −50.1 to −43.9‰ with several outliers, generally decreasing with depth. Gas samples collected by the Modular Formation Dynamics Testing (MDT) tool in the hydrate-bearing units were similarly composed mainly of methane, with up to 284 ppm ethane. The methane isotopic composition ranged from −48.2 to −48.0‰ in the C sand and from −48.4 to −46.6‰ in the D sand. Methane hydrogen isotopic composition ranged from −238 to −230‰, with slightly more depleted values in the deeper C sand. These results are consistent with the concept that the Eileen gas hydrates contain a mixture of deep-sourced, microbially biodegraded thermogenic gas, with lesser amounts of thermogenic oil-associated gas, and coal gas. Thermal gases are likely sourced from existing oil and gas accumulations that have migrated up-dip and/or up-fault and formed gas hydrate in response to climate cooling with permafrost formation.     

A margin-wide BSR gas hydrate assessment: Canada’s Atlantic margin

It is the intent of this paper to explore a significant extent of an entire passive continental margin for hydrate occurrence to understand hydrate modes of occurrence, preferred geologic settings and estimate potential volumes of methane. The presence of gas hydrates offshore of eastern Canada has long been inferred from estimated stability zone calculations, but little physical evidence has been offered. An extensive set of 2-D and 3-D, single and multi-channel seismic reflection data comprising in excess of 140,000 line-km was analyzed. Bottom simulating reflections (BSR) were unequivocally identified at seven sites, ranging between 250 and 445 m below the seafloor and in water depths of 620-2850 m. The combined area of the BSRs is 9311 km², which comprises a small proportion of the entire theoretical stability zone along the Canadian Atlantic margin (∼715,165 km²). The BSR within at least six of these sites lies in a sedimentary drift deposit or sediment wave field, indicating the likelihood of grain sorting and potential porosity and permeability (reservoir) development. Although there are a variety of conditions required to generate and recognize a BSR, one might assume that these sites offer the most potential for highest hydrate concentration and exploitation. Total hydrate in formation at the sites of recognized BSR’s is estimated at 17 to 190 × 10⁹ m³ or 0.28 to 3.12 × 10¹³ m³ of methane gas at STP. Although it has been shown that hydrate can exist without a BSR, the results from this regional study argue that conservative estimates of the global reserve of hydrate along continental margins are necessary.     

Present temperature field and Cenozoic thermal history in the Dongpu depression,Bohai Bay Basin,North China

The Dongpu depression is located in the southern Bohai Bay Basin, North China, and it has abundant oil and gas reserves. There has been no systematic documentation of this depression's temperature field and thermal history. In this article, the present geothermal gradient and heat flow were calculated for 68 wells on the basis of 892 formation-testing data from 523 wells. Moreover, the Cenozoic thermal history was reconstructed using 466 vitrinite reflectance data from 105 wells. The results show that the Dongpu depression is characterized by a medium-temperature field between stable and active tectonic areas, with an average geothermal gradient of 34.8 °C/km and an average heat flow of 66.8 mW/m². The temperature field in the Dongpu depression is significantly controlled by the Changyuan, Huanghe, and Lanliao basement faults and thin lithosphere thickness. The geothermal gradient twice experienced high peaks. One peak was during the Shahejie 3 Formation depositional period, ranging from 45 °C/km to 48 °C/km, and the second peak was in the middle and late of the Dongying Formation depositional period, ranging from 39 °C/km to 40 °C/km, revealing that the Dongpu depression experienced two strong tectonic rifts during the geothermal gradient high peak periods. The geothermal gradient began to decrease from the Neogene, and the geothermal gradient is 31–34 °C/km at the present day. In addition, these results reveal that source rock thermal evolution is controlled by the paleo temperature field of the Dongying Formation depositional period in the Dongpu depression. This study may provide a geothermal basis for deep oil and gas resource evaluation in the Dongpu depression.     

Simulation of paleotectonic stress fields and quantitative prediction of multi-period fractures in shale reservoirs: A case study of the Niutitang Formation in the Lower Cambrian in the Cen'gong block,South China

Reservoirs where tectonic fractures significantly impact fluid flow are widespread. Industrial-level shale gas production has been established from the Lower Cambrian Niutitang Formation in the Cen'gong block, South China; the practice of exploration and development of shale gas in the Cen'gong block shows that the abundance of gas in different layers and wells is closely related to the degree of development of fractures. In this study, the data obtained from outcrop, cores, and logs were used to determine the developmental characteristics of such tectonic fractures. By doing an analysis of structural evolution, acoustic emission, burial history, logging evaluation, seismic inversion, and rock mechanics tests, 3-D heterogeneous geomechanical models were established by using a finite element method (FEM) stress analysis approach to simulate paleotectonic stress fields during the Late Hercynian—Early Indo-Chinese and Middle-Late Yanshanian periods. The effects of faulting, folding, and variations of mechanical parameters on the development of fractures could then be identified. A fracture density calculation model was established to determine the quantitative development of fractures in different stages and layers. Favorable areas for shale gas exploration were determined by examining the relationship between fracture density and gas content of three wells. The simulation results indicate the magnitude of minimum principal stress during the Late Hercynian — Early Indo-Chinese period within the Cen'gong block is −100 ∼ −110 MPa with a direction of SE-NW (140°–320°), and the magnitude of the maximum principal stress during the Middle-Late Yanshanian period within the Cen'gong block is 150–170 MPa with a direction of NNW-SSE (345°–165°). During the Late Hercynian — Early Indo-Chinese period, the mechanical parameters and faults play an important role in the development of fractures, and fractures at the downthrown side of the fault are more developed than those at the uplifted side; folding plays an important role in the development of fractures in the Middle-Late Yanshanian period, and faulting is a secondary control. This 3-D heterogeneous geomechanical modelling method and fracture density calculation modelling are not only significant for prediction of shale fractures in complex structural areas, but also have a practical significance for the prediction of other reservoir fractures.     

Effects of composition and pore structure on the reservoir gas capacity of Carboniferous shale from Qaidam Basin,China

Shale adsorption and breakthrough pressure are important indicators of shale gas development and key factors in evaluating the reservoir capacities of shales. In this study, geochemical tests, pore-structure tests, methane adsorption tests, and breakthrough-pressure tests were conducted on shales from the Carboniferous Hurleg Formation in eastern Qaidam Basin. The effects of the shale compositions and pore structures on the adsorption and breakthrough pressures were studied, and the reservoir capacities of the shales were evaluated by analyzing the shale adsorptions and sealing effects. The results indicate that the organic carbon content was only one of factors in affecting the adsorption capacity of the shale samples while the effect of the clay minerals was limited. Based on the positive correlation between the adsorption capacity and specific surface area of the shale, the specific surface area of the micropores can be used as an indicator to determine the adsorption capacity of shale. The micro-fracturing of brittle minerals, such as quartz, create a primary path for shale gas breakthrough, whereas the expansion of clay minerals with water greatly increases the breakthrough pressure in the shale samples. Methane adsorption tests showed that maximum methane adsorption for shale samples Z045 and S039 WAS 0.107 and 0.09655 mmol/g, respectively. The breakthrough pressure was 39.36 MPa for sample S039, maintained for 13 days throughout the experiment; however, no breakthrough was observed in sample Z045 when subjected to an injected pressure of 40 MPa for 26 days. This indicates that sample Z045, corresponding to a depth of 846.24 m, exhibited higher adsorption capacity and a better reservoir-sealing effect than sample S039 (498.4 m depth). This study provides useful information for future studies of Qaidam Basin shale gas exploration and development and for evaluation of shale quality.     

Effects of oil expulsion and pressure on nanopore development in highly mature shale: Evidence from a pyrolysis study of the Eocene Maoming oil shale,south China

The influence of oil-expulsion efficiency on nanopore development in highly mature shale was investigated by using anhydrous pyrolysis (425–600 °C) on solvent-extracted and non-extracted shales at a pressure of 50 MPa. Additional pyrolysis studies were conducted using non-extracted shales at pressures of 25 and 80 MPa to further characterize the impact of pressure on pore evolution at high maturity. The pore structures of the original shale and relevant artificially matured samples after pyrolysis were characterized by using low-pressure nitrogen and carbon-dioxide adsorption techniques, and gas yields during pyrolysis were measured. The results show that oil-expulsion efficiency can strongly influence gas generation and nanopore development in highly mature shales, as bitumen remained in shales with low oil expulsion efficiency significantly promotes gaseous hydrocarbon generation and nanopore (diameter < 10 nm) development. The evolution of micropores and fine mesopores at high maturity can be divided into two main stages: Stage I, corresponding to wet gas generation (EasyRo 1.2%–2.4%), and Stage II, corresponding to dry gas generation (EasyRo 2.4%–4.5%). For shales with low oil expulsion efficiency, nanopore (diameter < 10 nm) evolution increases rapidly in Stage I, whereas slowly in Stage II, and such difference between two stages may be attributed to the changes of the organic matter (OM)’s mechanical properties. Comparatively, for shales with high oil expulsion efficiency, the evolution grows slightly in Stage I, not as rapidly as shales with low efficiency, and decays in Stage II. The different pore evolution behaviors of these two types of shales are attributed to the contribution of bitumen. However, the evolution of medium–coarse mesopores and macropores (diameter >10 nm) remains flat at high maturation. In addition, high pressure can promote the development of micropores and fine mesopores in highly mature shales.     

New heat flow measurements in the Ulleung Basin, East Sea (Sea of Japan): relationship to local BSR depth, and implications for regional heat flow distribution

In July 2007, new marine heat flow data were collected at ten sites (HF01–10) in the central and southwestern sectors of the Ulleung Basin (East Sea or Sea of Japan) as part of regional gas hydrate research. In addition, cores were collected at five of these sites for laboratory analysis. The results show that the geothermal gradient ranged from 103–137 mK/m, and the in-situ thermal conductivity from 0.82–0.95 W/m·K. Laboratory measurements of thermal conductivity were found to deviate by as much as 40% from the in-situ measurements, despite the precautions taken to preserve the cores. Based on the in-situ conductivity, the heat flow was found to increase with water depth toward the center of the basin, ranging from 84–130 mW/m². Using a simple model, we estimated the heat flow from the depths of the BSR, and compared this with the observed heat flow. In our study area, the two sets of values were quite consistent, the observed heat flows being slightly higher than the BSR-derived ones. The evaluation of regional pre-1994 data revealed that the heat flow varied widely from 51–157 mW/m² in and around the basin. Due to a large scatter in these older data, a clear relationship between heat flow and water depth was not evident, in contrast to what would be expected for a rifted sedimentary basin. This raises the question as to whether the pre-1994 data represent the true background heat flow from the underlying basin crust since the basin opening, and/or whether they contain large measurement errors. In fact, evidence in support of the latter explanation exists. BSRs are generally found in the deep parts of the basin, and vary by only ±15 m in depth below the seafloor. From the average BSR depth, we inferred the background heat flow using a simple model, which in the case of the Ulleung Basin is approximately 120 and 80 mW/m² for 2.5 and 1 km below sea level, respectively.     

Sealing efficiency of caprocks: Experimental investigation of entry pressure measurement methods

Caprocks play a key role in hydrocarbon entrapment and in the geological storage of gas. Top seals inhibit vertical migration due to their low permeability and high entry pressure (PE). This study investigated four different techniques for measuring PE: (1) step by step method; (2) dynamic approach; (3) racking method; (4) residual pressure method. This article reports results on two samples: a carbonate (1.5 μDarcy (1.5 10⁻¹⁸ m²)) and a claystone (15 nDarcy (1.5 10⁻²⁰ m²)). On the carbonate sample, methods 1, 2 and 3 gave a PE value of 1.1 MPa, whilst method 4 gave a PE of 0.4 MPa. On the claystone sample, methods 1 and 2 gave a PE value around 12 MPa. The data allow us to consider best practices for PE measurements on caprocks. Methods 2 and 3 are the quickest and most accurate methods but show limitations in very low permeability porous media. Method 2 required three days to measure PE in the 15 nD claystone and experiments on 1 nD (10⁻²¹ m²) materials would take longer. Additional issues on mechanical stresses impact the result reliability since in methods 2 and 3 effective stress can significantly change during the experiment. Method 4 measures a snap-off pressure that is lower than the entry pressure value. Method 1 is a long experiment but is the most representative of in situ hydrocarbon migration though caprocks.     

Gas hydrate saturation from acoustic impedance and resistivity logs in the Shenhu area, South China Sea

During the China’s first gas hydrate drilling expedition -1 (GMGS-1), gas hydrate was discovered in layers ranging from 10 to 25 m above the base of gas hydrate stability zone in the Shenhu area, South China Sea. Water chemistry, electrical resistivity logs, and acoustic impedance were used to estimate gas hydrate saturations. Gas hydrate saturations estimated from the chloride concentrations range from 0 to 43% of the pore space. The higher gas hydrate saturations were present in the depth from 152 to 177 m at site SH7 and from 190 to 225 m at site SH2, respectively. Gas hydrate saturations estimated from the resistivity using Archie equation have similar trends to those from chloride concentrations. To examine the variability of gas hydrate saturations away from the wells, acoustic impedances calculated from the 3 D seismic data using constrained sparse inversion method were used. Well logs acquired at site SH7 were incorporated into the inversion by establishing a relation between the water-filled porosity, calculated using gas hydrate saturations estimated from the resistivity logs, and the acoustic impedance, calculated from density and velocity logs. Gas hydrate saturations estimated from acoustic impedance of seismic data are ∼10-23% of the pore space and are comparable to those estimated from the well logs. The uncertainties in estimated gas hydrate saturations from seismic acoustic impedances were mainly from uncertainties associated with inverted acoustic impedance, the empirical relation between the water-filled porosities and acoustic impedances, and assumed background resistivity.     

Structural controls on the formation of BSR over a diapiric anticline from a dense MCS survey offshore southwestern Taiwan

A dense seismic reflection survey with up to 250-m line-spacing has been conducted in a 15 × 15 km wide area offshore southwestern Taiwan where Bottom Simulating Reflector is highly concentrated and geochemical signals for the presence of gas hydrate are strong. A complex interplay between north–south trending thrust faults and northwest–southeast oblique ramps exists in this region, leading to the formation of 3 plunging anticlines arranged in a relay pattern. Landward in the slope basin, a north–south trending diapiric fold, accompanied by bright reflections and numerous diffractions on the seismic profiles, extends across the entire survey area. This fold is bounded to the west by a minor east-verging back-thrust and assumes a symmetric shape, except at the northern and southern edges of this area, where it actively overrides the anticlines along a west-verging thrust, forming a duplex structure. A clear BSR is observed along 67% of the acquired profiles. The BSR is almost continuous in the slope basin but poorly imaged near the crest of the anticlines. Local geothermal gradient values estimated from BSR sub-bottom depths are low along the western limb and crest of the anticlines ranging from 40 to 50 °C/km, increase toward 50–60 °C/km in the slope basin and 55–65 °C/km along the diapiric fold, and reach maximum values of 70 °C/km at the southern tip of the Good Weather Ridge. Furthermore, the local dips of BSR and sedimentary strata that crosscut the BSR at intersections of any 2 seismic profiles have been computed. The stratigraphic dips indicated a dominant east–west shortening in the study area, but strata near the crest of the plunging anticlines generally strike to southwest almost perpendicular to the direction of plate convergence. The intensity of the estimated bedding-guided fluid and gas flux into the hydrate stability zone is weaker than 2 in the slope basin and the south-central half of the diapiric fold, increases to 7 in the northern half of the diapiric fold and plunging anticlines, and reaches a maximum of 16 at the western frontal thrust system. Rapid sedimentation, active tectonics and fluid migration paths with significant dissolved gas content impact on the mechanism for BSR formation and gas hydrate accumulation. As we begin to integrate the results from these studies, we are able to outline the regional variations, and discuss the importance of structural controls in the mechanisms leading to the gas hydrate emplacements.     

Geothermometry and geobarometry of overpressured lower Paleozoic gas shales in the Jiaoshiba field,Central China: Insight from fluid inclusions in fracture cements

The Wufeng-Longmaxi organic-rich shales host the largest shale gas fields of China. This study examines sealed fractures within core samples of the Wufeng-Longmaxi shales in the Jiaoshiba shale gas field in order to understand the development of overpressures (in terms of magnitude, timing and burial) in Wufeng-Longmaxi shales and thus the causes of present-day overpressure in these Paleozoic shale formations as well as in all gas shales. Quartz and calcite fracture cements from the Wufeng-Longmaxi shale intervals in four wells at depth intervals between 2253.89 m and 3046.60 m were investigated, and the fluid composition, temperature, and pressure during natural fracture cementation determined using an integrated approach consisting of petrography, Raman spectroscopy and microthermometry. Many crystals in fracture cements were found to contain methane inclusions only, and aqueous two-phase inclusions were consistently observed alongside methane inclusions in all cement samples, indicating that fluid inclusions trapped during fracture cementation are saturated with a methane hydrocarbon fluid. Homogenization temperatures of methane-saturated aqueous inclusions provide trends in trapping temperatures that Th values concentrate in the range of 198.5 °C–229.9 °C, 196.2 °C-221.7 °C for quartz and calcite, respectively. Pore-fluid pressures of 91.8–139.4 MPa for methane inclusions, calculated using the Raman shift of C-H symmetric stretching (v₁) band of methane and equations of state for supercritical methane, indicate fluid inclusions trapped at near-lithostatic pressures. High trapping temperature and overpressure conditions in fluid inclusions represent a state of temperature and overpressure of Wufeng-Longmaxi shales at maximum burial and the early stage of the Yanshanian uplift, which can provide a key evidence for understanding the formation and evolution of overpressure. Our results demonstrate that the main cause of present-day overpressure in shale gas deposits is actually the preservation of moderate-high overpressure developed as a result of gas generation at maximum burial depths.