Preservation of Mesoproterozoic age deep burial fluid signatures,NW Scotland

Bedding-parallel fibrous calcite is a widely developed feature of mudrock successions, reflecting conditions of fluid overpressure (Stoneley, 1983, Parnell et al., 2000, Cobbold et al., 2013). The calcite preserves signatures of fluids developed during deep burial, including hydrocarbons. Most studied examples are of Phanerozoic (<540 Ma) age. This study reports well-preserved fibrous calcite in the Mesoproterozoic (∼1180 Ma) Stoer Group, NW Scotland. The fibrous calcite occurs immediately above a unit of carbonaceous black shale. If hydrocarbons were generated from the black shales, they could have contributed to the development of fluid overpressure, but there is no direct evidence for this. The calcite reflects the original deep burial fluid, rather than a later overprint, because (i) it has a distribution related to stratigraphy, (ii) the bedding-parallel fibres have not been recrystallized, and (iii) later veining is at high angles to bedding. The calcite contains fluid inclusions, and has yielded stable isotope and entrained volatile data, indicating the potential to record diagenetic processes over one billion years ago.     

Petrological and geochemical constraints on diagenesis and deep burial dissolution of the Ordovician carbonate reservoirs in the Tazhong area,Tarim Basin,NW China

Deeply buried (4500–7000 m) Ordovician carbonate reservoirs in the Tazhong area, Tarim Basin, NW China show obvious heterogeneity with porosity from null in limestones and sweet dolostones to 27.8% in sour dolostones, from which economically important oils, sour gas and condensates are currently being produced. Petrographic features, C, O, Sr isotopes were determined, and fluid inclusions were analyzed on diagenetic calcite, dolomite and barite from Ordovician reservoirs to understand controls on the porosity distribution. Ordovician carbonate reservoirs in the Tazhong area are controlled mainly by initial sedimentary environments and eo-genetic and near-surface diagenetic processes. However, vugs and pores generated from eogenetic and telogenetic meteoric dissolution were observed to have partially been destroyed due to subsequent compaction, filling and cementation. In some locations or wells (especially ZG5-ZG7 Oilfield nearby ZG5 Fault), burial diagenesis (e.g. thermochemical sulfate reduction, TSR) probably played an important role in quality improvement towards high-quality reservoirs. C2 calcite and dolomite cements and barite have fluid inclusions homogenization temperatures (Ths) from 86 to 113 °C, from 96 to 128 °C and from 128 to 151 °C, respectively. We observed petrographically corroded edges of these high-temperature minerals with oil inclusions, indicating the dissolution must have occurred under deep-burial conditions. The occurrence of TSR within Ordovician carbonate reservoirs is supported by C3 calcite replacement of barite, and the association of sulfur species including pyrite, anhydrite or barite and elemental sulfur with hydrocarbon and ¹²C-rich (as low as −7.2‰ V-PDB) C3 calcite with elevated Ths (135–153 °C). The TSR may have induced burial dissolution of dolomite and thus probably improved porosity of the sour dolostones reservoirs at least in some locations. In contrast, no significant burial dissolution occurred in limestone reservoirs and non-TSR dolostone reservoirs. The deeply buried sour dolostone reservoirs may therefore be potential exploration targets in Tarim Basin or elsewhere in the world.     

Diagenesis and origin of calcite cement in the Flemish Pass Basin sandstone reservoir (Upper Jurassic): Implications for porosity development

The Flemish Pass Basin is a deep-water basin located offshore on the continental passive margin of the Grand Banks, eastern Newfoundland, which is currently a hydrocarbon exploration target. The current study investigates the petrographic characteristics and origin of carbonate cements in the Ti-3 Member, a primary clastic reservoir interval of the Bodhrán Formation (Upper Jurassic) in the Flemish Pass Basin.The Ti-3 sandstones with average Q_86.0F_3.1R_10.9 contain various diagenetic minerals, including calcite, pyrite, quartz overgrowth, dolomite and siderite. Based on the volume of calcite cement, the investigated sandstones can be classified into (1) calcite-cemented intervals (>20% calcite), and (2) poorly calcite-cemented intervals (porous). Petrographic analysis shows that the dominant cement is intergranular poikilotopic (300–500 μm) calcite, which stared to form extensively at early diagenesis. The precipitation of calcite occured after feldspar leaching and was followed by corrosion of quartz grains. Intergranular calcite cement hosts all-liquid inclusions mainly in the crystal core, but rare primary two-phase (liquid and vapor) fluid inclusions in the rims ((with mean homogenization temperature (T_h) of 70.2 ± 4.9 °C and salinity estimates of 8.8 ± 1.2 eq. wt.% NaCl). The mean δ¹⁸O and δ¹³C isotopic compositions of the intergranular calcite are −8.3 ± 1.2‰, VPDB and −3.0 ± 1.3‰, VPDB, respectively; whereas, fracture-filling calcite has more depleted δ¹⁸O but similar δ¹³C values. The shale normalized rare earth element (REE_SN) patterns of calcite are generally parallel and exhibit slightly negative Ce anomalies and positive Eu anomalies. Fluid-inclusion gas ratios (CO₂/CH₄ and N₂/Ar) of calcite cement further confirms that diagenetic fluids originated from modified seawater. Combined evidence from petrographic, microthermometric and geochemical analyses suggest that (1) the intergranular calcite cement precipitated from diagenetic fluids of mixed marine and meteoric (riverine) waters in suboxic conditions; (2)the cement was sourced from the oxidation of organic matters and the dissolution of biogenic marine carbonates within sandstone beds or adjacent silty mudstones; and (3) the late phases of the intergranular and fracture-filling calcite cements were deposited from hot circulated basinal fluids.Calcite cementation acts as a main controlling factor on the reservoir quality in the Flemish Pass reservoir sandstones. Over 75% of initial porosity was lost due to the early calcite cementation. The development of secondary porosity (mostly enlarged, moldic pores) and throats by later calcite dissolution due to maturation of organic matters (e.g., hydrocarbon and coals), was the key process in improving the reservoir quality.     

Fluid inclusion and microfabric studies on Zechstein carbonates (Ca2) and related fracture mineralizations – New insights on gas migration in the Lower Saxony Basin (Germany)

New petrographic and fluid inclusion data from core samples of Upper Permian dolomitic limestone (Hauptdolomit, Zechstein group, Stassfurt carbonate sequence) from a gas field located at the northern border of the Lower Saxony Basin (LSB) essentially improve the understanding of the basin development. The gas production at the locality is characterized by very high CO₂ concentrations of 75–100% (with CH₄ and N₂).Samples consist of fine grained, mostly laminated and sometimes brecciated dolomitic limestone (mudstone/wackestone) from the transition zone between the shallow water zone (platform) and the upper slope. The study focuses on migration fluids, entrapped as fluid inclusions in diagenetic anhydrite, calcite, and fluorite, and in syn-diagenetic microfractures, as well as on the geochemistry of fluorite fracture mineralizations, obtained by LA-ICP-MS analysis. Fluid inclusion studies show that the diagenetic fluid was rich in H₂ONaClCaCl₂. Recrystallized anhydrite contains aqueous inclusions with homogenization temperatures (T_h) of ca. 123 °C, but somewhat higher T_h of ca. 142 °C was found for calcite cement followed by early Fluorite A with T_h of 147 °C. A later Fluorite B preserves gas inclusions and brines with maximum T_h of 156 °C. Fluorite B crystallized in fractures during the mobilization of CO₂-bearing brines. Crossing isochores for co-genetic aqueous-carbonic and carbonic inclusions indicate fluid trapping conditions of 180–200 °C and 900–1000 bars. δ¹³C-isotopic ratios of gas trapped in fluid inclusions suggest an organic origin for CH₄, while the CO₂ is likely of inorganic origin.Basin modelling (1D) shows that the fault block structure of the respective reservoir has experienced an uplift of >1000 m since Late Cretaceous times.The fluid inclusion study allows us to, 1) model the evolution of the LSB and fluid evolution by distinguishing different fluid systems, 2) determine the appearance of CO₂ in the geological record and, 3) more accurately estimate burial and uplift events in individual parts of the LSB.     

Petroleum accumulation in the deeply buried reservoirs in the northern Dongying Depression,Bohai Bay Basin,China: New insights from fluid inclusions,natural gas geochemistry,and 1-D basin modeling

The deeply buried reservoirs (DBRs) from the Lijin, Shengtuo and Minfeng areas in the northern Dongying Depression of the Bohai Bay Basin, China exhibit various petroleum types (black oil-gas condensates) and pressure systems (normal pressure-overpressure) with high reservoir temperatures (154–185 °C). The pressure-volume-temperature-composition (PVTX) evolution of petroleum and the processes of petroleum accumulation were reconstructed using integrated data from fluid inclusions, stable carbon isotope data of natural gas and one-dimensional basin modeling to trace the petroleum accumulation histories.The results suggest that (1) the gas condensates in the Lijin area originated from the thermal cracking of highly mature kerogen in deeper formations. Two episodes of gas condensate charging, which were evidenced by the trapping of non-fluorescent gas condensate inclusions, occurred between 29-25.5 Ma and 8.6–5.0 Ma with strong overpressure (pressure coefficient, P_c = 1.68–1.70), resulting in the greatest contribution to the present-day gas condensate accumulation; (2) the early yellow fluorescent oil charge was responsible for the present-day black oil accumulation in well T764, while the late blue-white oil charge together with the latest kerogen cracked gas injection resulted in the present-day volatile oil accumulation in well T765; and (3) the various fluorescent colors (yellow, blue-white and blue) and the degree of bubble filling (F_v) (2.3–72.5%) of the oil inclusions in the Minfeng area show a wide range of thermal maturity (API gravity ranges from 30 to 50°), representing the charging of black oil to gas condensates. The presence of abundant blue-white fluorescent oil inclusions with high Grain-obtaining Oil Inclusion (GOI) values (35.8%, usually >5% in oil reservoirs) indicate that a paleo-oil accumulation with an approximate API gravity of 39–40° could have occurred before 25 Ma, and gas from oil cracking in deeper formations was injected into the paleo-oil reservoir from 2.8 Ma to 0 Ma, resulting in the present-day gas condensate oil accumulation. This oil and gas accumulation model results in three oil and gas distribution zones: 1) normal oil reservoirs at relatively shallow depth; 2) gas condensate reservoirs that originated from the mixture of oil cracking gas with a paleo-oil reservoir at intermediate depth; and 3) oil-cracked gas reservoirs at deeper depth.The retardation of organic matter maturation and oil cracking by high overpressure could have played an important role in the distribution of different origins of gas condensate accumulations in the Lijin and Minfeng areas. The application of oil and gas accumulation models in this study is not limited to the Dongying Depression and can be applied to other overpressured rift basins.     

Stable carbon isotope ratios of CH4-rich gas inclusions in shale-hosted fracture-fill mineralization: A tool for tracing hydrocarbon generation and migration in shale plays for oil and gas

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.     

Fracturing and calcite cementation controlling fluid flow in the shallow-water carbonates of the Jandaíra Formation,Brazil

The shallow-marine carbonate rocks of the Jandaíra Formation have been subject to significant permeability variations through time due to various events of fracturing and calcite cementation. As a consequence, the Jandaíra Formation accommodated fluid flow only during specific moments in time. We reconstructed these episodes of fluid flow based on isotope characterizations and microscope characteristics of calcite veins and host rock cements. The Jandaíra Formation, which belongs to the post-rift sequence of the Potiguar Basin in northeast Brazil, was deposited from the Turonian onward until a marine regression exposed it in the Campanian. Due to the subaerial exposure, meteoric waters flushed out marine connate waters, leading to an event of early diagenesis and full cementation of the Jandaíra Formation. Fluid flow through the resulting impermeable carbonate formation appears to be closely related to fracturing. Fracturing in the Late Cretaceous induced a drastic increase in permeability, giving rise to extensive fluid circulation. Host rock dissolution associated to the circulating fluids led to calcite vein cementation within the fracture network, causing it to regain an impermeable and sealing character. In the research area, fluid flow occurred during early burial of the Jandaíra Formation at estimated depths of 400–900 m. This study documents the first application of fluid inclusion isotope analysis on vein precipitates, which allowed full isotopic characterization of the paleo-fluids responsible for calcite vein cementation. The fluid inclusion isotope data indicate that upwelling of groundwater from the underlying Açu sandstones provided the fluids to the fracture network. In Miocene times, renewed tectonic compression of a lower intensity created a secondary fracture network in the Jandaíra Formation. The density of this fracture network, however, was too low to induce a new episode of fluid circulation. As a result, this tectonic event is associated with the development of barren extensional fractures.     

Natural sealed fractures in mudrocks: A case study tied to burial history from the Barnett Shale,Fort Worth Basin,Texas, USA

The Mississippian Barnett Shale (Texas, USA), consisting of organic-rich shales and limestones, hosts the largest gas fields of North America. This study examines sealed fractures from core and outcrop samples of the Barnett Shale of the Fort Worth Basin and aims to: 1) characterize the phases occurring in the fractures from samples having experienced different burial histories; 2) establish a paragenetic sequence to relate the timing of fracture origin and sealing with the burial history of the basin; and 3) contribute to the understanding of the mechanisms of fracture formation in shales, including overpressure origin.Four fracture generations were distinguished in the most deeply buried core samples by characterizing the sealing minerals petrographically and geochemically. The generations were inserted into the framework of a reconstructed burial history for the Fort Worth Basin, which allowed a time sequence for fracture development to be established. This in turn allowed inference of conditions of fracture development, and consideration of fracture mechanisms as well as the origin of the parent fluids of sealing minerals.Type 1 fractures formed during early mechanical compaction (at a few 10 s to 100 m of depth) of still not fully cemented sediments. Type 2 fractures formed during moderate burial (∼2 km), from slightly modified seawater. Their timing is consistent with overpressure generated during rapid deposition and differential compaction of Pennsylvanian lithologies during the onset of the Ouachita compressional event. Type 3 fractures formed during deep burial (>3 km) from silica-rich basinal brines possibly derived from clay diagenesis. Type 4 fractures formed at very deep burial (>4 km), from hot and ¹⁸O-rich fluids, carrying light oil (20-30 API) and record the opening of the fluid system after hydrocarbon migration.Differences are highlighted between the timing and thermal regimes under which fractures formed in Barnett lithologies from different areas of the basin, this suggesting that extrapolation of outcrop observations to subsurface must be used with due care.     

Palaeopressure reconstruction to explain observed natural hydraulic fractures in the Cleveland Basin

Natural fractures observed within the Lower Jurassic shales of the Cleveland Basin show evidence that pore pressure must have exceeded the lithostatic pressure in order to initiate horizontal fractures observed in cliff sections. Other field localities do not show horizontal fracturing, indicating lower pore pressures there. Deriving the burial history of the basin from outcrop, VR and heat-flow data gives values of sedimentation rates and periods of depositional hiatus which can be used to assess the porosity and pore pressure evolution within the shales. This gives us our estimate of overpressure caused by disequilibrium compaction alone, of 11 MPa, not sufficient to initiate horizontal fractures. However, as the thermal information shows us that temperatures were in excess of 95 °C, secondary overpressure mechanisms such as clay diagenesis and hydrocarbon generation occurred, contributing an extra 11 MPa of overpressure. The remaining 8.5 MPa of overpressure required to initiate horizontal fractures was caused by fluid expansion due to hydrocarbon generation and tectonic compression related to Alpine orogenic and Atlantic opening events. Where horizontal fractures are not present within the Lower Jurassic shales, overpressure was unable to build up as high due to proximity to the lateral draining of pressure within the Dogger Formation. The palaeopressure reconstruction techniques used within this study give a quick assessment of the pressure history of a basin and help to identify shales which may currently have enhanced permeability due to naturally-occurring hydraulic fractures.     

Kilometer-scale fault-related thermal anomalies in tight gas sandstones

Upper Carboniferous sandstones make one of the most important tight gas reservoirs in Central Europe. This study integrates a variety of geothermometers (chlorite thermometry, fluid inclusion microthermometry and vitrinite reflection measurements) to characterize a thermal anomaly in a reservoir outcrop analog (Piesberg quarry, Lower Saxony Basin), which is assumed responsible for high temperatures of circa 300 °C, deteriorating reservoir quality entirely. The tight gas siliciclastics were overprinted with temperatures approximately 90–120 °C higher compared to outcropping rocks of a similar stratigraphic position some 15 km to the west. The local temperature increase can be explained by circulating hydrothermal fluids along the fault damage zone of a large NNW-SSE striking fault with a displacement of up to 600 m in the east of the quarry, laterally heating up the entire exposed tight gas sandstones. The km-scale lateral extent of this fault-bound thermal anomaly is evidenced by vitrinite reflectance measurements of meta-anthracite coals (VR_rot ∼ 4.66) and the temperature-related diagenetic overprint. Data suggest that this thermal event and the associated highest coalification was reached prior to peak subsidence during Late Jurassic rifting (162 Ma) based on K-Ar dating of the <2 μm fraction of the tight gas sandstones. Associated stable isotope data from fluid inclusions, hosted in a first fracture filling quartz generation (T ∼ 250 °C) close to lithostatic fluid pressure (P ∼ 1000 bars), together with authigenic chlorite growth in mineralized extension fractures, demonstrate that coalification was not subject to significant changes during ongoing burial. This is further evidenced by the biaxial reflectance anisotropy of meta-anthracite coals. A second event of quartz vein formation occurred at lower temperatures (T ∼ 180 °C) and lower (hydrostatic) pressure conditions (P ∼ 400 bars) and can be related to basin inversion. This second quartz generation might be associated with a second event of illite growth and K-Ar ages of 96.5–106.7 Ma derived from the <0.2 μm fraction of the tight gas sandstones.This study demonstrates the exploration risk of fault-bound thermal anomalies by deteriorating entirely the reservoir quality of tight gas sandstones with respect to porosity and permeability due to the cementation with temperature-related authigenic cements. It documents that peak temperatures are not necessarily associated with peak subsidence. Consequently, these phenomena need to be considered in petroleum system models to avoid, for example, overestimates of burial depth and reservoir quality.     

Geological models of gas in place of the Longmaxi shale in Southeast Chongqing,South China

Gas-in-place (GIP) is one of the primary controlling factors in shale gas production, but studies examining GIP have been lacking for the Lower Silurian Longmaxi shale in South China. In the present study, a suite of Longmaxi shale samples was collected from an exploratory well in Southeast Chongqing, South China, and the adsorption parameters were fitted using a supercritical Dubinin-Radushkevich (SDR) model based on the high-pressure methane adsorption experiment data for the samples. The results show that the adsorbed phase density and the adsorbed gas capacity of the samples have a positive correlation with the content of total organic carbon (TOC) but a negative correlation with temperature. Combined with the geological characteristics of the Longmaxi shale in Southeast Chongqing, GIP models were constructed under three different fluid pressure conditions. The absolute adsorbed amount of the samples increases and later decreases with increasing depth with a maximum corresponding to depths between 800 and 1200 m. The fluid pressure coefficient has no obvious effect on the absolute adsorbed amount when burial depth is over 2000 m but controls the free gas content. Overpressure primarily increases the free gas content and thus increases the total gas content. The free gas content of the Longmaxi shale in the Pengshui Block is reduced to 47%–58% of that in the Fuling Block, which is the main reason for its low gas production. Further exploration of the Longmaxi Formation should be expanded to deeper burial shales in the eastern area of Southeast Chongqing.     

Geochemistry,reservoir characterization and hydrocarbon generation potential of lacustrine shales: A case of YQ-1 well in the Yuqia Coalfield,northern Qaidam Basin,NW China

Ever since a breakthrough of marine shales in China, lacustrine shales have been attracting by the policy makers and scientists. Organic-rich shales of the Middle Jurassic strata are widely distributed in the Yuqia Coalfield of northern Qaidam Basin. In this paper, a total of 42 shale samples with a burial depth ranging from 475.5 m to 658.5 m were collected from the Shimengou Formation in the YQ-1 shale gas borehole of the study area, including 16 samples from the Lower Member and 26 samples from the Upper Member. Geochemistry, reservoir characteristics and hydrocarbon generation potential of the lacustrine shales in YQ-1 well were preliminarily investigated using the experiments of vitrinite reflectance measurement, maceral identification, mineralogical composition, carbon stable isotope, low-temperature nitrogen adsorption, methane isothermal adsorption and rock eval pyrolysis. The results show that the Shimengou shales have rich organic carbon (averaged 3.83%), which belong to a low thermal maturity stage with a mean vitrinite reflectance (R_o) of 0.49% and an average pyrolytic temperature of the generated maximum remaining hydrocarbon (T_max) of 432.8 °C. Relative to marine shales, the lacustrine shales show low brittleness index (averaged 34.9) but high clay contents (averaged 55.1%), high total porosities (averaged 13.71%) and great Langmuir volumes (averaged 4.73 cm⁻³ g). Unlike the marine and marine-transitional shales, the quartz contents and brittleness index (BI) values of the lacustrine shales first decrease then increase with the rising TOC contents. The kerogens from the Upper Member shales are dominant by the oil-prone types, whereas the kerogens from the Lower Member shales by the gas-prone types. The sedimentary environment of the shales influences the TOC contents, thus has a close connection with the hydrocarbon potential, mineralogical composition, kerogen types and pore structure. Additionally, in terms of the hydrocarbon generation potential, the Upper Member shales are regarded as very good and excellent rocks whereas the Lower Member shales mainly as poor and fair rocks. In overall, the shales in the top of the Upper Member can be explored for shale oil due to the higher free hydrocarbon amount (S₁), whereas the shales in the Lower Member and the Upper Member, with the depths greater than 1000 m, can be suggested to explore shale gas.     

Pore characterization and methane sorption capacity of over-mature organic-rich Wufeng and Longmaxi shales in the southeast Sichuan Basin,China

Currently, the Upper Ordovician Wufeng (O₃w) and Lower Silurian Longmaxi (S₁l) Formations in southeast Sichuan Basin have been regarded as one of the most important target plays of shale gas in China. In this work, using a combination of low-pressure gas adsorption (N₂ and CO₂), mercury injection porosimetry (MIP) and high-pressure CH₄ adsorption, we investigate the pore characteristics and methane sorption capacity of the over-mature shales, and discuss the main controlling factors for methane sorption capacity and distribution of methane gas in pore spaces.Low pressure CO₂ gas adsorption shows that micropore volumes are characterized by three volumetric maxima (at about 0.35, 0.5 and 0.85 nm). The reversed S-shaped N₂ adsorption isotherms are type Ⅱ with hysteresis being noticeable in all the samples. The shapes of hysteresis loop are similar to the H3 type, indicating the pores are slit- or plate-like. Mesopore size distributions are unimodal and pores with diameters of 2–16 nm account for the majority of mesopore volume, which is generally consistent with MIP results. The methane sorption capacities of O₃w-S₁l shales are in a range of 1.63–3.66 m³/t at 30 °C and 10 MPa. Methane sorption capacity increase with the TOC content, surface area and micropore volume, suggesting organic matter might provide abundant adsorption site and enhance the strong methane sorption capacity. Samples with higher quartz content and lower clay content have larger sorption capacity. Our data confirmed that the effects of temperature and pressure on methane sorption capacity of shale formation are opposite to some extent, suggesting that, during the burial or uplift stage, the gas sorption capacity of hydrocarbon reservoirs can be expressed as a function of burial depth. Based on the adsorption energy theory, when the pore diameter is larger than 2 nm, much methane molecular will be adsorbed in pores space with distance to pore wall less than 2 nm; while free gas is mainly stored in the pore space with distance to pore wall larger than 2 nm. Distributions of adsorption space decrease with the increasing pore size, while free gas volume increase gradually, assuming the pore are cylindrical or sphere. Particularly, when the pore size is larger than 30 nm, the content of adsorbed gas space volume is very low and its contribution to the all gas content is negligible.     

Modeling free gas content of the Lower Paleozoic shales in the Weiyuan area of the Sichuan Basin,China

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.     

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.     

Saddle dolomite and calcite cements as records of fluid flow during basin evolution: Paleogene carbonates,United Arab Emirates

Field observations indicate that tectonic compression, anticline formation and concomitant uplift events of marine Paleogene carbonates in eastern United Arab Emirates, which are related to the Zagros Orogeny, have induced brecciation, karstification, and carbonate cementation in vugs and along faults and fractures. Structural analysis, stable isotopes and fluid inclusion microthermometry are used to constrain the origin and geochemical evolution of the fluids. Fluid flow was related to two tectonic deformation phases. Initially, the flux of moderately ⁸⁷Sr-rich basinal NaCl–MgCl₂–H₂O brines along reactivated deep-seated strike-slip faults have resulted in the precipitation of saddle dolomite in fractures and vugs and in dolomitization of host Eocene limestones (δ¹⁸O_V-PDB −15.8‰ to −6.2‰; homogenization temperatures of 80–115 °C and salinity of 18–25 wt.% eq. NaCl). Subsequently, compression and uplift of the anticline was associated with incursion of meteoric waters and mixing with the basinal brines, which resulted in the precipitation of blocky calcite cement (δ¹⁸O_V-PDB −22‰ to −12‰; homogenization temperatures of 60–90 °C and salinity of 4.5–9 wt.% eq. NaCl). Saddle dolomite and surrounding blocky calcite have precipitated along the pre- and syn-folding E–W fracture system and its conjugate fracture sets. The stable isotopes coupled with fluid-inclusion micro-thermometry (homogenization temperatures of ≤50 °C and salinity of <1.5 wt.% eq. NaCl) of later prismatic/dogtooth and fibrous calcites, which occurred primarily along the post-folding NNE–SSW fracture system and its conjugate fracture sets, suggest cementation by descending moderately ⁸⁷Sr-rich, cool meteoric waters. This carbonate cementation history explains the presence of two correlation trends between the δ¹⁸O_V-PDB and δ¹³C_V-PDB values: (i) a negative temperature-dependent oxygen isotope fractionation trend related to burial diagenesis and to the flux of basinal brines, and (ii) positive brine-meteoric mixing trend. This integrated study approach allows better understanding of changes in fluid composition and circulation pattern during evolution of foreland basins.     

Mineral types and organic matters of the Ordovician-Silurian Wufeng and Longmaxi Shale in the Sichuan Basin,China: Implications for pore systems,diagenetic pathways,and reservoir quality in fine-grained sedimentary rocks

Mineral types (detrital and authigenic) and organic-matter components of the Ordovician-Silurian Wufeng and Longmaxi Shale (siliceous, silty, argillaceous, and calcareous/dolomitic shales) in the Sichuan Basin, China are used as a case study to understand the control of grain assemblages and organic matter on pores systems, diagenetic pathway, and reservoir quality in fine-grained sedimentary rocks. This study has been achieved using a combination of petrographic, geochemical, and mercury intrusion methods. The results reveal that siliceous shale comprises an abundant amount of diagenetic quartz (40–60% by volume), and authigenic microcrystalline quartz aggregates inhibit compaction and preserve internal primary pores as rigid framework for oil filling during oil window. Although silty shale contains a large number of detrital silt-size grains (30–50% by volume), which is beneficial to preserve interparticle pores, the volumetric contribution of interparticle pores (mainly macropores) is small. Argillaceous shale with abundant extrabasinal clay minerals (>50% by volume) undergoes mechanical and chemical compactions during burial, leading to a near-absence of primary interparticle pores, while pores preserved between clay platelets are dominant with more than 10 nm in pore size. Pore-filling calcite and dolomite precipitated during early diagenesis inhibit later compaction in calcareous/dolomitic shale, but the cementation significantly reduces the primary interparticle pores. Pore-throat size distributions of dolomitic shale show a similar trend with silty shale. Besides argillaceous shale, all of the other lithofacies are dominated by OM pores, which contribute more micropores and mesopores and is positively related to TOC and quartz contents. The relationship between pore-throat size and pore volume shows that most pore volumes are provided by pore throats with diameters <50 nm, with a proportion in the order of siliceous (80.3%) > calcareous/dolomitic (78.4%) > silty (74.9%) > argillaceous (61.3%) shales. In addition, development degree and pore size of OM pores in different diagenetic pathway with the same OM type and maturity show an obvious difference. Therefore, we suggest that the development of OM pores should take OM occurrence into account, which is related to physical interaction between OM and inorganic minerals during burial diagenesis. Migrated OM in siliceous shale with its large connected networks is beneficial for forming more and larger pores during gas window. The result of the present work implies that the study of mineral types (detrital and authigenic) and organic matter-pores are better understanding the reservoir quality in fine-grained sedimentary rocks.     

The role played by carbonate cementation in controlling reservoir quality of the Triassic Skagerrak Formation,Norway

Anomalously high porosities up to 30% at burial depth of >3000 m along with varying amounts and types of carbonate cements occur in the fluvial channel sandstone facies of the Triassic Skagerrak Formation, Central Graben, Norway. However, porosities of the Skagerrak Formation are lower in the Norwegian sector than in the UK sector. In this study, petrographic analysis, core examination, scanning electron microscopy, elemental mapping, carbon and oxygen isotope, fluid inclusion and microgeometry analysis are performed to determine the diagenesis and direct influence on reservoir quality, with particular focus on the role played by carbonate cementation. The sandstones are mainly fine-grained lithic-arkosic to sub-arkosic arenites and display a wide range of intergranular volumes (2.3%–43.7% with an average of 23.6%). Porosity loss is mainly due to compaction (av. 26.6%) with minor contribution from cementation (av. 12.1%). The carbonate cements are patchy in distribution (from trace to 20.7%) and appear as various types e.g. calcretes (i.e. calcareous concreted gravels), poikilitic sparite and sparry ferroan dolomite, and euhedral or/and aggregated ankerite/ferroan dolomite crystals. This study highlights the association of carbonate precipitation with the remobilisation of carbonate from intra-Skagerrak calcretes during early burial stage i.e. <500 m. During deeper burial, compaction is inhibited by carbonate cements, resulting high intergranular volume of up to 32% and 29% for fine- and medium-grained sandstones, respectively. Carbonate cement dissolution probably results from both meteoric water flow with CO₂ during shallow burial, and organic CO₂ and carboxylic acid during deep burial. The maximum intergranular volume enhanced by dissolution of early carbonate cements is calculated to 8% and 5% for fine- and medium-grained sandstones, respectively. Compaction continues to exert influence after dissolution of carbonate cements, which results in a loss of ∼6% intergranular volume for fine- and medium-grained sandstones. Reservoir quality of the Norwegian sector is poorer than that of the UK sector due to a lower coverage of clay mineral coats e.g. chlorite, later and deeper onset of pore fluid overpressure, lower solubility of carbonate compared to halite, and a higher matrix content.     

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.