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1.
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. 相似文献
2.
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. 相似文献
3.
Knowledge of the full present-day stress tensor and pore pressure has significant applications in the exploration and production of conventional and unconventional hydrocarbon reservoirs. The Darling Basin of New South Wales, Australia, is an old sedimentary basin (Late Cambrian/Silurian to Early Carboniferous) in which there was limited information about the present-day stress field prior to this study. In this paper we evaluate the contemporary stress field of the Darling Basin using a dataset from recent exploration wells and perform a geomechanical risk assessment with respect to borehole stability, fracture/fault generation and reactivation. Our interpretations of borehole failures in borehole image logs reveal a prevailing east-west orientation of the maximum horizontal stress throughout the Darling Basin. The estimates of the magnitudes for the vertical, minimum and maximum horizontal stress in the studied wells indicate a transition between thrust and strike-slip faulting stress regime at 600–700 m depths, where the magnitude of vertical stress and minimum horizontal stress are close to each other. However, the presence of borehole breakouts and drilling-induced tensile fractures, that we observe in the image logs at greater depths (900–2100 m) indicate a transition into a strike-slip tectonic stress regime below a depth range of approximately 700–900 m. These findings are in agreement with overcoring stress measurements east and west of the investigated wells. Furthermore, there are several Neogene-to-Recent geological structures in the study area that indicate thrust faulting with an east-west oriented maximum horizontal stress orientation around this old sedimentary basin. The consistency between the orientation of maximum horizontal stress determined from wellbore data and neotectonic structures is significant, and implies that horizontal stress orientations derived from very recent geological features may be valuable inputs to geomechanical models in the absence of wellbore or other data. However, the recent surface geological structures suggest a thrust faulting stress regime that is in slight contrast to the transition between thrust and strike-slip stress regime (SH > Sh ∼ Sv) indicated by petroleum data, and highlights a potential pitfall of using neotectonic structures in geomechanical models. In particular, careful attention and verification should be made when using neotectonic structures for input, calibration or confirmation of geomechanical models, especially in intraplate tectonic settings such as Australia. 相似文献
4.
The Ordovician is the most important exploration target in the Tabei Uplift of the Tarim Basin, which contains a range of petroleum types including solid bitumen, heavy oil, light oil, condensate, wet gas and dry gas. The density of the black oils ranges from 0.81 g/cm3 to 1.01 g/cm3 (20 °C) and gas oil ratio (GOR) ranges from 4 m3/m3 to 9300 m3/m3. Oil-source correlations established that most of the oils were derived from the Mid-Upper Ordovician marine shale and carbonate and that the difference in oil properties is mainly attributed to hydrocarbon alteration and multi-stage accumulation. In the Tabei Uplift, there were three main periods of hydrocarbon accumulation in the late Caledonian stage (ca. 450–430 Ma), late Hercynian stage (ca. 293–255 Ma) and the late Himalayan stage (ca. 12–2 Ma). The oil charging events mainly occurred in the late Caledonian and late Hercynian stage, while gas charging occurred in the late Hercynian stage. During the late Caledonian stage, petroleum charged the reservoirs lying east of the uplift. However, due to a crustal uplifting episode in the early Hercynian (ca. 386–372 Ma), most of the hydrocarbons were transformed by processes such as biodegradation, resulting in residual solid bitumen in the fractures of the reservoirs. During the late Hercynian Stage, a major episode of oil charging into Ordovician reservoirs took place. Subsequent crustal uplift and severe alteration by biodegradation in the west-central Basin resulted in heavy oil formation. Since the late Himalayan stage when rapid subsidence of the crust occurred, the oil residing in reservoirs was exposed to high temperature cracking conditions resulting in the production of gas and charged from the southeast further altering the pre-existing oils in the eastern reservoirs. A suite of representative samples of various crude oils including condensates, lights oils and heavy oils have been collected for detailed analysis to investigate the mechanism of formation. Based on the research it was concluded that the diversity of hydrocarbon physical and chemical properties in the Tabei Uplift was mainly attributable to the processes of biodegradation and gas washing. The understanding of the processes is very helpful to predict the spatial distribution of hydrocarbon in the Tabei Uplift and provides a reference case study for other areas. 相似文献
5.
Two sets of Lower Paleozoic organic-rich shales develop well in the Weiyuan area of the Sichuan Basin: the Lower Cambrian Jiulaodong shale and the Lower Silurian Longmaxi shale. The Weiyuan area underwent a strong subsidence during the Triassic to Early Cretaceous and followed by an extensive uplifting and erosion after the Late Cretaceous. This has brought about great changes to the temperature and pressure conditions of the shales, which is vitally important for the accumulation and preservation of shale gas. Based on the burial and thermal history, averaged TOC and porosity data, geological and geochemical models for the two sets of shales were established. Within each of the shale units, gas generation was modeled and the evolution of the free gas content was calculated using the PVTSim software. Results show that the free gas content in the Lower Cambrian and Lower Silurian shales in the studied area reached the maxima of 1.98–2.93 m3/t and 3.29–4.91 m3/t, respectively (under a pressure coefficient of 1.0–2.0) at their maximum burial. Subsequently, the free gas content continuously decreased as the shale was uplifted. At present, the free gas content in the two sets of shales is 1.52–2.43 m3/t and 1.94–3.42 m3/t, respectively (under a current pressure coefficient of 1.0–2.0). The results are roughly coincident with the gas content data obtained from in situ measurements in the Weiyuan area. We proposed that the Lower Cambrian and Lower Silurian shales have a shale gas potential, even though they have experienced a strong uplifting. 相似文献
6.
Gil Young Kim Buyanbat Narantsetseg Dong Geun Yoo 《Marine Georesources & Geotechnology》2021,39(1):34-43
AbstractGeophysical evidence indicating the presence of gas hydrate has been found in the Ulleung Basin, which lies off the east coast of the Korean Peninsula; however, hydrate distribution in the basin is not well understood. Logging-while-drilling data for 13 sites in the Ulleung Basin, East Sea, were obtained to investigate the distribution pattern of gas hydrate. Most of the sites yielded log data indicating the presence of gas hydrate. Prominent fractures (both resistive and conductive fractures) were clearly identified on the resistivity borehole images, particularly at seismic chimney sites. Resistive fractures, which contain large amounts of gas hydrate, are prominent in the seismic chimney sites. The strike and dip of each fracture was calculated and displayed on a stereographic plot and rosette diagram. From the fracture orientations on the stereographic plots, the maximum horizontal stress is NW–SE, reflecting the regional stress regime around the Ulleung Basin, although the fracture orientations are broadly distributed, indicating that the fracture pattern is not well-ordered on the rosette diagram. The fracture dips are between 36.46° and 63.66°; the range of dip azimuths is 0.94°–359°, and exhibit little change with depth. The dip azimuths are generally westerly to southwesterly. 相似文献
7.
Variability in the Lower Bowland shale microstructure is investigated here, for the first time, from the centimetre to the micrometre scale using optical and scanning electron microscopy (OM, SEM), X-Ray Diffraction (XRD) and Total Organic Carbon content (TOC) measurements. A significant range of microtextures, organic-matter particles and fracture styles was observed in rocks of the Lower Bowland shale, together with the underlying Pendleside Limestone and Worston Shale formations encountered the Preese Hall-1 Borehole, Lancashire, UK. Four micro-texture types were identified: unlaminated quartz-rich mudstone; interlaminated quartz- and pyrite-rich mudstone; laminated quartz and pyrite-rich mudstone; and weakly-interlaminated calcite-rich mudstone. Organic matter particles are classified into four types depending on their size, shape and location: multi-micrometre particles with and without macropores: micrometre-size particles in cement and between clay minerals; multi-micrometre layers; and organic matter in large pores. Fractures are categorized into carbonate-sealed fractures; bitumen-bearing fractures; resin-filled fractures; and empty fractures. We propose that during thermal maturation, horizontal bitumen-fractures were formed by overpressuring, stress relaxation, compaction and erosional offloading, whereas vertical bitumen-bearing, resin-filled and empty fractures may have been influenced by weak vertical joints generated during the previous period of veining. For the majority of samples, the high TOC (>2 wt%), low clay content (<20 wt%), high proportion of quartz (>50 wt%) and the presence of a multi-scale fracture network support the increasing interest in the Bowland Shale as a potentially exploitable oil and gas source. The microtextural observations made in this study highlight preliminary evidence of fluid passage or circulation in the Bowland Shale sequence during burial. 相似文献
8.
As shale oil occurs primarily in micro–nano pores and fractures, research about the effect of pore structure on shale oil accumulation has great significance for shale oil exploration and development. The effect of pore structure on shale oil accumulation in the lower third member of the Shahejie formation (Es3l), Zhanhua Sag, eastern China was investigated using gas adsorption, soxhlet extraction, nuclear magnetic resonance (NMR) analysis, and field emission scanning electron microscope (FE-SEM) observation. The results indicated that the samples contained a larger amount of ink-bottle-shaped and slit-shaped pores after extraction than before extraction. The pore volume and specific surface area of the samples were approximately 2.5 times larger after extraction than before extraction. Residual hydrocarbon occurred primarily in the free-state form in pores with diameters of 10–1000 nm, which can provide sufficient pore volume for free hydrocarbon accumulation. Therefore, pores with diameters of 10–1000 nm were regarded as “oil-enriched pores”, which are effective pores for shale oil exploration, whereas pores with diameters smaller than 10 nm were regarded as “oil-ineffective pores”. Samples with only well-developed small pores with diameters smaller than 1000 nm showed high oil saturation, whereas samples with both small pores and also relatively large pores and micro-fractures presented low oil saturation. As the minimum pore size allowing fluid expulsion is 1000 nm, pores with diameters greater than 1000 nm were considered as “oil-percolated pores”. Large pores and micro-fractures are generally interconnected and may even form a complex fracture mesh, which greatly improves the permeability of shale reservoirs and is beneficial to fluid discharge. 相似文献
9.
The study integrates petrographical and lithological data from deep exploration wells and outcrops in northern Iraq to better understand the sedimentary environments present in the basin and to evaluate the depositional evolution of the Paleozoic rocks in Iraq. The studied Paleozoic successions are represented by five sedimentary cycles of intracratonic sequences. These are dominated mainly by siliciclastic and mixed sedimentary packages, and are separated by major and minor unconformity surfaces. These cycles are as follow: the Ordovician cycle, represented by the Khabour Formation; the Silurian cycle, represented by the Akkas Formation; the Middle-Late Devonian to Early Carboniferous cycle, represented by the Chalki, Pirispiki, Kaista, Ora and Harur formations; the Permian–Carboniferous cycle, represented by the Ga’ara Formation and late Permian cycle, represented by the Chia Zairi Formation. Generally, the cycles are characterized by siliciclastic and mixed carbonate–clastic facies with abrupt changes during Late Paleozoic reflecting the environmental and tectonic events during this period. The Ordovician Khabour Formation is suggested to be of shallow marine environment of deposition with stacked transgressive and regressive cycles that are eustatically controlled. The shale of Silurian Akkas Formation was deposited in open-marine environment. Depositional regimes in the Late Devonian to Early Carboniferous are considered as a continuation of deposition in the subsiding basin with a wide geographic distribution that reflect the epicontinental or epeiric seas in a homoclinic ramp setting. The Permo-Carboniferous Ga’ara Formation was deposited in continental to paralic environment while the Late Permian Chia Zairi Formation represents the carbonate platform deposition. The study revealed that potential source rocks may include some shale beds of the Khabour Formation, hot shales of Akkas Formation and the shales of Ora Formation. The sandstones of the Khabour, Akkas and Kaista formations have good reservoir potential. The Late Permian carbonates of Chia Zairi Formation may be self-sourcing and contain multiple reservoirs. The occurrence of shale as source rocks and limestone as reservoir rocks and some evaporates as sealing horizons make the formation as a reservoir in its own right. 相似文献
10.
选择轮南主体区剖面七条和临近凹陷剖面两条，利用压力数值模拟手段，对轮南地区的压力场演化进行了恢复和模拟。结合实测压力资料和钻井资料，发现部分地区石炭系和上奥陶统中存在弱超压、寒武系在凹陷内存在超压。通过分析，石炭系超压在轮南主体区主要是水热增压作用和泥岩转换作用造成的，在凹陷内则可能主要由于欠压实引起。上奥陶统内部的超压和石炭系在形成时间、特征和发育机理上相似，不过轮南地区上奥陶统覆盖区域较少。寒武系超压和三个成藏期相对应，在凹陷内形成明显的三期超压现象，以喜山期超压幅度最大。整体上看，石炭系和上奥陶统弱超压，对成藏动力方面贡献不大，但是超压的形成增强了该层的封闭性，对喜山期天然气成藏有重要影响。寒武系超压为油气初次运移提供了动力，但是超压幅度有限，推测其在油气二次运移过程中贡献不大。 相似文献
11.
《Marine and Petroleum Geology》2012,32(1):53-69
The objectives of our study were to assess the thickness, lateral extent, organic richness and maturity of the potential source rocks in Hungary and to estimate the volumes of hydrocarbons generated, in order that potential shale gas and shale oil plays could be identified and characterised.The Upper Triassic Kössen Marl in south-west Hungary could represent the best potential shale gas/shale oil play, due to its high organic richness, high maturity and the presence of fracture barriers. The area of gas- and oil-generative maturity is around 720 km2 with the unexpelled petroleum estimated to be up to 9 billion barrel oil-equivalent.The Lower Jurassic sediments of the Mecsek Mountains and under the Great Plain contain fair quality gas-prone source rocks, with low shale gas potential, except for a thin Toarcian shale unit which is richer in organic matter. The latter could form a potential shale gas play under the Great Hungarian Plain, if it is thicker locally.The Lower Oligocene Tard Clay in north-east Hungary could represent the second best potential shale oil play, due to its organic richness, favourable maturity and large areal extent (4500 km2) with around 7 billion barrel oil-equivalent estimated in-place volume of petroleum.Middle Miocene marine formations could represent locally-developed shale gas plays; they have fair amounts of organic matter and a mixture of type II/III kerogen, but their vertical and lateral variability is high.The Upper Miocene lacustrine Endrőd Marl contains less organic matter and the kerogen is mainly type III, which is not favourable for shale gas generation. The high carbonate and clay content, plus the lack of upper and lower fracture barriers would represent additional production challenges. 相似文献
12.
The area reviewed covers the Mid-Norway continental margin between latitudes 62°N and 68°N. Main structural elements, as defined at the base Cretaceous level, are the Tröndelag Platform, underlying the inner shelf, the Möre and Vöring Basins, located beneath the outer shelf and slope, and the Möre Platform and the Outer Vöring Plateau, forming a base of slope trend of highs. Sediments contained in the Mid-Norway Basin range in age from Late Palaeozoic to Cenozoic. The basement was consolidated during the Caledonian orogenic cycle. Devonian and Early Carboniferous wrench movements along the axis of the Arctic-North Atlantic Caledonides are thought to have preceded the Namurian onset of crustal extension. Rifting processes were intermittently active for some 270 My until crustal separation between Greenland and Fennoscandia was achieved during the Early Eocene. During the evolution of the Norwegian-Greenland Sea rift system a stepwise concentration of tectonic activities to its axial zone (the area of subsequent continental separation) is observed. During the Late Palaeozoic to Mid-Jurassic a broad zone was affected by tensional faulting. During the Late Jurassic and Cretaceous the Tröndelag Platform was little affected by faulting whilst major rift systems in the Möre and Vöring Basins subsided rapidly and their shoulders became concomitantly upwarped. During the latest Cretaceous and Early Palaeogene terminal rifting phase only the western Möre and Vöring Basins were affected by intrusive and extrusive igneous activity. Following the Early Eocene crustal separation and the onset of sea floor spreading in the Norwegian-Greenland Sea, the Vöring segment of the Mid-Norway marginal basin subsided less rapidly than the Möre segment. During the Early and Mid Tertiary, minor compressional deformations affected the Vöring Basin and to a lesser degree the Möre Basin. Tensional forces dominated the Late Palaeozoic to Early Cenozoic evolution of the Mid-Norway Basin and effected strain mainly in the area where the crust was weakened by the previous lateral displacements. The lithosphere thinned progressively and the effects of the passively upwelling hot asthenospheric material became more pronounced. Massive dyke invasion of the thinned crust preceded its rupture. 相似文献
13.
Reconnaissance seismic shot in 1971/72 showed a number of well defined seismic anomalies within the East Sengkang Basin which were interpreted as buried reefs. Subsequent fieldwork revealed that Upper Miocene reefs outcropped along the southern margin of the basin. A drilling programme in 1975 and 1976 proved the presence of shallow, gas-bearing, Upper Miocene reefs in the northern part of the basin. Seismic acquisition and drilling during 1981 confirmed the economic significance of these discoveries, with four separate accumulations containing about 750 × 109 cubic feet of dry gas in place at an average depth of 700 m. Kampung Baru is the largest field and contains over half the total, both reservoir quality and gas deliverability are excellent. Deposition in the East Sengkang Basin probably started during the Early Miocene. A sequence of Lower Miocene mudstones and limestones unconformably overlies acoustic basement which consists of Eocene volcanics. During the tectonically active Middle Miocene, deposition was interrupted by two periods of deformation and erosion. Carbonate deposition became established in the Late Miocene with widespread development of platform limestones throughout the East Sengkang Basin. Thick pinnacle reef complexes developed in the areas where reef growth could keep pace with the relative rise in sea level. Most reef growth ceased at the end of the Miocene and subsequent renewed clastic sedimentation covered the irregular limestone surface. Late Pliocene regression culminated in the Holocene with erosion. The Walanae fault zone, part of a major regional sinistral strike-slip system, separates the East and West Sengkang Basins. Both normal and reverse faulting are inferred from seismic data and post Late Pliocene reverse faulting is seen in outcrop. 相似文献
14.
A 1500 km long segment of a fracture zone exhibiting continuity of trend and offset with the Atlantis fracture zone (30°N) was mapped with bathymetric, seismic reflection, and magnetic profiles between the outer continental shelf and the abyssal hills off northwest Africa. The fracture zone segment occurs in crust of Mesozoic age dated tentatively by the identification of remanent magnetic anomalies.Lithospheric plate motions in a frame of reference fixed with respect to Africa are deduced along the fracture zone. During the Early and Middle Jurassic (? 180 to > 155 my) the plate motion was east-west described by a rotation of 10° about a pole located at 36° ± 2°N, 17.5 ± 1°W with respect to Africa. The location of this pole indicates that the opening of the Atlantic between North America and Africa was independent of the opening between North America and Europe with an intervening plate boundary in the position of the present Azores-Gibraltar ridge. The rotation changed to northwest-southeast during the Late Jurassic (> 155 to about 150 my), when the azimuth to the pole of plate rotation jumped about 20° of arc eastward from the azimuth to the prior pole. The northwest-southeast relative rotation continued during the Late Jurassic and Early Cretaceous (about 150 to about 100 my). The azimuth to the rotational pole appears to have migrated progressively westward toward the Cenozoic pole. 相似文献
15.
Studying complex pore structures is the key to understanding the mechanism of shale gas accumulation. FIB-SEM (focused ion beam-scanning electron microscope) is the mainstream and effective instrument for imaging nanopores in gas shales. Based on this technology, 2D and 3D characteristics of shale samples from Lower Silurian Longmaxi formation in southern Sichuan Basin were investigated. 2D experimental results show that the pores in shale are nanometer-sized, and the structure of those nanopores can be classified into three types: organic pores, inorganic pores and micro fractures. Among the three types, organic pores are dominantly developed in the OM (organic matter) with three patterns such as continuous distributed OM, OM between clay minerals and OM between pyrite particles, and the size of organic pores range from 5 nm to 200 nm.Inveresly, inorganic pores and micro fractures are less developed in the Longmaxi shales. 3D digital rocks were reconstructed and segmented by 600 continuous images by FIB cutting and SEM imaging simultaneously. The pore size distribution and porosity can be calculated by this 3D digital core, showing that its average value is 32 nm and porosity is 3.62%.The 3D digital porosity is higher than its helium porosity, which can be regarded as one important parameter for evaluation of shale gas reserves. The 2D and 3D characterized results suggest that the nanometer-sized pores in organic matter take up the fundamental storage space for the Longmaxi shale. These characteristics have contributed to the preservation of shale gas in this complex tectonic area. 相似文献
16.
According to the preliminary geological data of gas hydrate bearing-sediments (GHBS) at site GMGS3-W19 in the third Chinese expedition to drill gas hydrates in 2015, a production model using three different recovery pressures was established to assess the production feasibility from both production potential and geomechanical response. The simulation results show that for this special Class 1 deposit, it is a little hard for gas production rate to reach the commercial extraction rate because the degree of hydrate dissociation is limited due to the low reservoir permeability and the permeable burdens. However, the free gas accumulating in the lower part of the GHBS can significantly increase gas-to-water ratio. It also generates many secondary hydrates in the GHBS at the same time. Decreasing the well pressure can be beneficial to gas recovery, but the recovery increase is not obvious. In term of geomechanical response of the reservoir during the gas recovery, the permeable burdens are conducive to reduction of the sediment deformation, though they don't facilitate the gas recovery rate. In addition, significant stress concentration is observed in the upper and lower edges of GHBS around the borehole during depressurization because of high pressure gradient, and the greater the well pressure drop, the more obvious the phenomenon. Yield failures and sand production easily take place in the edges. Therefore, in order to achieve the purpose of safe, efficient and long-term gas production, a balance between the production pressure and reservoir stability should be reached at the hydrate site. The production pressure difference and sand production must be carefully controlled and the high stress concentration zones need strengthening or sand control treatment during gas production. Besides, the sensitivity analyses show that the hydrate saturation heterogeneity can affect the production potential and geomechanical response to some extent, especially the water extraction rate and the effective stress distribution and evolution. Increasing GHBS and its underlying free gas formation permeabilities can enhance the gas production potential, but it probably introduces geomechanical risks to gas recovery operations. 相似文献
17.
Fluid inclusion gases in minerals from shale hosted fracture-fill mineralization have been analyzed for stable carbon isotopic ratios of CH4 using a crushing device interfaced to an isotope ratio mass spectrometer (IRMS). The samples of Paleozoic strata under study originate from outcrops and wells in the Rhenish Massif and Campine Basin, Harz Mountains, and the upper slope of the Southern Permian Basin. Fracture-fill mineralization hosted by Mesozoic strata was sampled from drill cores in the Lower Saxony Basin. Some studied sites are candidates for shale gas exploration in Germany. Samples of Mesozoic strata are characterized by abundant calcite-filled horizontal fractures which preferentially occur in TOC-rich sections of the drilled sediments. Only rarely are vertical fractures filled with carbonates and/or quartz in drill cores from Mesozoic strata but in Paleozoic shale they occur frequently. The δ13C(CH4) values of fluid inclusions in calcite from horizontal fractures hosted by Mesozoic strata suggest that gaseous hydrocarbons were generated during the oil/early gas window and that the formation of horizontal fractures seems to be related to hydraulic expulsion fracturing. The calculated maturity of the source rocks at the time of gas generation lies below the maturity derived from measured vitrinite reflectance. Thus, the formation of horizontal fractures and trapping of gas that was generated in the oil and/or early gas window obviously occurred prior to maximal burial. Rapidly increasing vitrinite reflectance data seen locally can be explained by hydrothermal alteration, as indicated by increasing δ13C (CH4–CO2) values in fluid inclusions. The formation of vertical fractures in studied Mesozoic sediments is related to stages of post-burial inversion; gas-rich inclusions in fracture filling minerals recorded the migration of gas that had probably been generated instantaneously, rather than cumulatively, from high to overmature source rocks. Since no evidence is given for the presence of early generated gas in studied Paleozoic shale, it appears likely that major gas loss from shales occurred due to deformation and uplift of these sediments in response to the Variscan Orogeny. 相似文献
18.
New interest in the potential for shale gas in the United Kingdom (UK) has led to renewed exploration for hydrocarbons in the Carboniferous age Bowland–Hodder shales under Central and Northern England. Following an incidence of induced seismicity from hydraulic fracturing during 2010 at Preese Hall, Lancashire, the publically available databases quantifying the in-situ stress orientation of the United Kingdom have shown to be inadequate for safe planning and regulation of hydraulic fracturing. This paper therefore reappraises the in-situ stress orientation for central and northern England based wholly on new interpretations of high-resolution borehole imaging for stress indicators including borehole breakouts and drilling-induced tensile fractures. These analyses confirm the expected north northwest – south southeast orientation of maximum horizontal in-situ stress identified from previous studies (e.g. Evans and Brereton, 1990). The dual-caliper data generated by Evans and Brereton (1990) yields a mean SHmax orientation of 149.87° with a circular standard deviation of 66.9°. However the use of borehole imaging without incorporation of results from older dual-caliper logging tools very significantly decreases the associated uncertainty with a mean SHmax orientation of 150.9° with a circular standard deviation of 13.1°.The use of high-resolution borehole imaging is thus shown to produce a more reliable assessment of in-situ stress orientation. The authors therefore recommend that the higher resolution of such imaging tools should therefore be treated as a de-facto standard for assessment of in-situ stress orientation prior to rock testing. Use of borehole imaging should be formally instituted into best practice or future regulations for assessment of in-situ stress orientation prior to any hydraulic fracturing operations in the UK. 相似文献
19.
In this study, 32 experimental measurements on the isothermal adsorption of methane for 18 shale samples from China's three largest continental oil basins—Songliao, Bohai Bay, and Ordos basins—were used to construct comprehensive polynomial simulation and prediction models for Langmuir volume and Langmuir pressure. The models were based on shale properties (total organic carbon (TOC) content, amount of residual hydrocarbon S1, and mineral composition of rocks) and adsorption condition (temperature) using a weighted sum of multiple variables. The influences of various factors were quantitatively characterized, and the prediction accuracy was verified. Langmuir volume is mainly affected by temperature, shale TOC content, amount of residual hydrocarbon, and clay mineral content; Langmuir pressure is mainly affected by clay, carbonate, feldspar and illite content (because shale pore size can be affected by shale mineral composition). Based on the resource potential and the producibility of shale gas, the area suitable for shale gas exploration and development should have high abundance of organic matter (TOC and residual hydrocarbon S1), low clay mineral content and feldspar content, high conversion rate of montmorillonite to illite (strong diagenesis), and high carbonate content. The comprehensive polynomial prediction model can effectively simulate and predict Langmuir volume and Langmuir pressure, thereby reducing the amount of work necessary for evaluation of shale gas resource potential and economic feasibility. 相似文献
20.
This study presents results for pyrolysis experiments conducted on immature Type II and IIs source rocks (Kimmeridge Clay, Dorset UK, and Monterey shale, California, USA respectively) to investigate the impact of high water pressure on source rock maturation and petroleum (oil and gas) generation. Using a 25 ml Hastalloy vessel, the source rocks were pyrolysed at low (180 and 245 bar) and high (500, 700 and 900 bar) water pressure hydrous conditions at 350 °C and 380 °C for between 6 and 24 h. For the Kimmeridge Clay (KCF) at 350 °C, Rock Eval HI of the pyrolysed rock residues were 30–44 mg/g higher between 6 h and 12 h at 900 bar than at 180 bar. Also at 350 °C for 24 h the gas, expelled oil, and vitrinite reflectance (VR) were all reduced by 46%, 61%, and 0.25% Ro respectively at 900 bar compared with 180 bar. At 380 °C the retardation effect of pressure on the KCF was less significant for gas generation. However, oil yield and VR were reduced by 47% and 0.3% Ro respectively, and Rock Eval HI was also higher by 28 mg/g at 900 bar compared with 245 bar at 12 h. The huge decrease in gas and oil yields and the VR observed with an increase in water pressure at 350 °C for 24 h and 380 °C for 12 h (maximum oil generation) were also observed for all other times and temperatures investigated for the KCF and the Monterey shale. This shows that high water pressure significantly retards petroleum generation and source rock maturation. The retardation of oil generation and expulsion resulted in significant amounts of bitumen and oil being retained in the rocks pyrolysed at high pressures, suggesting that pressure is a possible mechanism for retaining petroleum (bitumen and oil) in source rocks. This retention of petroleum within the rock provides a mechanism for oil-prone source rocks to become potential shale gas reservoirs. The implications from this study are that in geological basins, pressure, temperature and time will all exert significant control on the extent of petroleum generation and source rock maturation for Type II source rocks, and that the petroleum retained in the rocks at high pressures may explain in part why oil-prone source rocks contain the most prolific shale gas resources. 相似文献