Defining the 3D geometry of thin shale units in the Sleipner reservoir using seismic attributes

Defining the 3D geometry and internal architecture of reservoirs is important for prediction of hydrocarbon volumes, petroleum production and storage potential. Many reservoirs contain thin shale layers that are below seismic resolution, which act as impermeable and semi-permeable layers within a reservoir. Predicting the storage volume of a reservoir with thin shale layers from conventional seismic data is an issue due to limited seismic resolution. Further, gas chimneys indicative of gas migration pathways through thin shale layers, are not easily defined by conventional seismic data. Additional information, such as borehole data, can be used to aid mapping of shale layers, but making lateral predictions from 1D borehole data has high uncertainty. This paper presents an integrated workflow for quantitative seismic interpretation of thin shale layers and gas chimneys in the Utsira Formation of the Sleipner reservoir. The workflow combines the use of attribute and spectral analysis to add resolution to conventional seismic amplitude data. Detailed interpretation of these analyses reveals the reservoirs internal thin shale architecture, and the presence of gas chimneys. The comprehensive interpretation of the reservoirs internal structure is used to calculate a new reservoir storage volume. This is done based on the distribution of sand and interpreted shale layers within the study area, for this active CO₂ storage site.     

Complex accumulation and leakage of YC21-1 gas bearing structure in Yanan sag,Qiongdongnan basin,South China Sea

YC21-1 is a gas-bearing structure found within the Yanan sag in the Qiongdongnan Basin, South China Sea. While the structure bears many geological similarities to the nearby YC13-1 gas field, it nevertheless does not contain commercially viable gas volumes. The main reservoirs of the YC21-1 structure contain high overpressures, which is greatly different from those of the YC13-1 structure. The pressure coefficients from drillstem tests, wireline formation tests and mud weights are above 2.1. Based on well-log analysis, illite content and vitrinite reflectance data of mudstones in well YC21-1-2, combining with tectonic and sedimentation characteristics, the timing and causes of overpressure generation are here interpreted. The results indicate the existence of two overpressure segments in the YC21-1 structure. The first overpressure segment resides mainly within the lower and the middle intervals of the Yinggehai Formation, and is interpreted to have been mainly caused by clay diagenesis, while disequilibrium compaction and hydrocarbon generation may also have contributed to overpressure generation. The second overpressure segment comprising the Sanya Formation (Pressure transition zone) and the Lingshui and Yacheng Formations (Hard overpressure zone) is interpreted to owe its presence to kerogen-to-gas cracking. According to petrography, homogenization temperature and salinity of fluid inclusions, two stages of oil-gas charge occurred within the main reservoirs. On the basis of overpressure causes and oil-gas charge history, combining with restored tectonic evolution and fluid inclusion characteristics, a complex accumulation and leakage process in the YC21-1 gas bearing structure has been interpreted. Collective evidence suggests that the first oil charge occurred in the Middle Miocene (circa 16.3–11.2 Ma). Small amount of oil generation and absence of caprocks led to the failure of oil accumulation. Rapid subsidence in the Pliocene and Quaternary gave rise to a sharp increase in geotemperature over a short period of time, leading to prolific gas-generation through pyrolysis and, consequently, overpressure within the main reservoirs (the second overpressure segment). During this period, the second gas charge occurred in the Pliocene and Quaternary (circa 4.5–0.4 Ma). The natural gas migrated in several phases, consisting of free and water soluble phases in a high-pressure environment. Large amounts of free gas are considered to have been consumed due to dissolution within formation water in highly pressured conditions. Water soluble gas could not accumulate in high point of structure. When the pore-fluid pressures in main reservoirs reached the fracture pressure of formation, free gas could leak via opened fractures within cracked caprocks. A repeated fracturing of caprocks may have consumed natural gas stored in formation water and have made water-soluble gas unsaturated. Therefore, the two factors including caprocks fracturing and dissolution of formation water are interpreted to be mainly responsible for the failure of natural gas accumulation in the YC21-1 structure.     

Hydrocarbon evolution for a north-south section of the South Caspian Basin

A 150 km length, 6-second deep, seismic line across the west central and north parts of the South Caspian Basin was used to construct quantitative dynamical, thermal and hydrocarbon evolution patterns. The depth of the west part of the 2-D section of the South Caspian Basin is almost 30 km. The computer program GEOPETII was used to provide quantitative evolution models. The procedure provided an opportunity to investigate the development dynamics of: excess fluid pressure, porosity retention, rock fracturing, compaction, heat transfer, maturity, generation pressure, kinetic hydrocarbon generation, migration and accumulation, together with solubility effects on hydrocarbon transport. The results suggest that: (i) Temperature is 350–400°C in the deepest part of the section at a depth of 26–29 km; (ii) The highest values of excess pressure nearly twice hydrostatic fluid pressure are in Jurassic and Cretaceous formations in the west part of the section, which has now subsided to a depth of about 20–27 km; (iii) Major oil and gas generation began in the last 10-5 MYBP, the migration in free-phase and in water solution occurring dominantly in the last few million years; (iv) Trapping of hydrocarbons took place mainly, but not exclusively, in the 3–9 km depth interval in the sands of the Productive Series of the Pilocene, embedded in a shale sequence; (v) Oil and gas filling of the shallow reservoirs by oil and gas is on-going today, indicating an extremely high productivity for any reservoir found in the offshore area; (vi) There is overlap with depth of oil and gas reservoirs, and the total amount of hydrocarbons estimated to be trapped is considerable; (vii) The high overpressure expected makes for a drilling hazard, but one which it is worthwhile to overcome if the anticipated oil and gas accumulations are encountered.     

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.     

Hydrocarbon accumulation model for Neogene traps in the Chengdao area,Bohai Bay Basin,China

Chengdao is an offshore area in the Bohai Bay Basin that contains approximately 25.7 × 10⁸ bbl of oil and gas reserves within the sandstone reservoirs in Neogene strata. However, previous predictions of hydrocarbon accumulation in Neogene traps are inaccurate, resulting in a current failure rate of 50% when drilling for hydrocarbons in this area. To build an improved exploration model for Neogene traps, we select 92 traps from Neogene strata in the Chengdao area to quantify the filling degree, which is an indicator of hydrocarbon accumulation efficiency. The quantified filling degree is based on actual geological and exploration data and differs significantly among various trap types. The filling degree of traps also varies significantly with their structural locations and decreases generally from the northwest to the southeast along the Chengbei Fault zone. Vertically, the filling degree is highly heterogeneous, initially increasing from the bottom to the middle of Neogene strata and then decreasing towards the top of the strata. These Neogene hydrocarbon reservoirs are sourced from the Paleogene, and as they lay vertically away from the source rocks, their hydrocarbon enrichment is constrained largely by hydrocarbon migration distance and vertical migration pathways. The sealing capacity of faults and cap rocks, sandbody orientation and reservoir sedimentary facies determine the maximum column height, which in turn affects the amount of hydrocarbon accumulation within these traps. A scatter plot analysis of individual controls and volumetric filling for each trap type is compiled using multivariate linear regression analysis to quantify controls and the dominant control of hydrocarbon accumulation is determined.     

Hydrocarbon gases in the crystalline rocks of the Gravberg-1 well,Swedish deep gas project

Desorbed gas analyses of cuttings from the Gravberg—1 well, the culmination of the Swedish deep gas project, were undertaken every 100 m from 219 to 5907 m. A sample at 6517 m, from sidetrack 2, was also included. The desorbed gas method performed by hot acid treatment in an evacuated system was superior to both ball mill crushing and thermodesorption methods. Two types of hydrocarbon gases were found in trace quantities. One type associated with the dolerite sills was an isotopically heavy, δ¹³C₁: −11 to −15‰, dry gas, with a methane content up to 98%. The other type, occurring throughout the granitic rocks, was an isotopically lighter gas, δ¹³C₁: −21 to −39 ‰, containing 30–45% of C₂C₄ olefins and paraffins were present in almost equal amounts in the second type of gas. The dry gas observed in the dolerites is assumed to be abiogenic gas existing in inclusions of basic minerals which react with acid during the analytical procedure. The other type of hydrocarbon gas is thought to be formed from H₂ and CO₂ by a catalytic reaction since it is mainly associated with the magnetic fraction of the rock. A Fischer-Tropsch reaction over a magnetite catalyst is the most likely reaction since it produces both paraffins and olefins. Studies on thin sections of cores and coarse cuttings suggest that the wet gas is not isolated in inclusions and the changes with time observed for a few thin sections indicate that it diffuses quite freely. The potential risks of contamination from drilling fluids and bit metamorphism were examined by comparing the hydrocarbon results with changes in the mud system, rate of penetration and bit life. Hydrocarbon analyses of a few mud additives were included as well. The result of these examinations plus the results of hydrocarbon analyses of cores from pilot core holes in the Siljan Crater suggest that the hydrocarbons observed in the cuttings are indigeneous.Comparing the results of the present study with other hydrocarbon occurrences outside of the Siljan Crater indicates that the hydrocarbons found in the Gravberg—1 well occur widespread in crustal rocks.     

Timing and mechanism of reservoir forming in the Upper Triassic Halahatang Formation,Yuqi block,Tarim Basin,northwestern China

The Yuqi block is an important area for oil and gas exploration in the northern Akekule uplift, Tarim Basin, northwestern China. The Upper Triassic Halahatang Formation (T₃h) within the Yuqi block can be subdivided into a lowstand system tract (LST), a transgressive system tract (TST), and a highstand system tract (HST), based on a study of initial and maximum flood surfaces. Oil in the lowstand system tract of the Halahatang Formation is characterized by medium to lightweight (0.8075 g/cm³–0.9258 g/cm³), low sulfur content (0.41%–1.4%), and high paraffin content (9.65%–10.25%). The distribution of oil and gas is principally controlled by low-amplitude anticlines and faults. Based on studies of fluorescence thin sections and homogenization temperatures of fluid inclusions, reservoirs in the T₃h were formed in at least two stages of hydrocarbon charge and accumulation. During the first stage (Jurassic–Cretaceous) both the structural traps and hydrocarbon reservoirs were initiated; during the second stage (Cenozoic) the structural traps were finally formed and the reservoirs were structurally modified. The reservoir-forming mechanism involved external hydrocarbon sources (i.e. younger reservoirs with oil and gas sourced from old rocks), two directions (vertical and lateral) of expulsion, and multi-stage accumulation. This model provides a theoretical fundament for future oil and gas exploration in the Tarim Basin and other similar basins in northwestern China.     

Effect of sedimentary heterogeneities on hydrocarbon accumulations in the Permian Shanxi Formation,Ordos Basin,China: Insight from an integrated stratigraphic forward and petroleum system modelling

Sedimentary heterogeneities are ubiquitous in nature and occur over a range of scales from core, reservoir to basin scales. They may thus exert significant influences on hydrocarbon generation, migration and accumulation. The sedimentary heterogeneities of the Permian Shanxi Formation in the Ordos Basin, China were modelled using Sedsim, a stratigraphic forward modelling program. The simulation results were then used to construct a 3D petroleum system model using PetroMod. The effects of sedimentary heterogeneities on hydrocarbon accumulations were evaluated by comparing the integrated Sedsim-PetroMod model with the classic 3D basin model. The Sedsim simulation shows that considerable sedimentary heterogeneities are present within the Shanxi Formation, as a result of the interplay of the initial topography, tectonic subsidence, base level change and sediment inputs. A variety of lithologies were developed both laterally and vertically within the Shanxi Formation at kilometre and metre scales, respectively, with mudstones mainly developed in the depositional centre, while sandstones developed in the southern and northern margin areas. A typical source-ward retrogradation is well developed within the Lower Shanxi Formation.A base-case classic 3D basin model was constructed to quantify the Permian petroleum system in the Ordos Basin. The geological and thermal models were calibrated using Vr and borehole temperature data. The source rocks of the Upper Paleozoic became mature (R_o > 0.5%) and high mature (R_o > 1.2%) in the late Triassic and late Jurassic, respectively, in the central and southern areas. During the Early Cretaceous, a tectonically induced geothermal event occurred in the southern Ordos Basin. This caused the source rocks to reach over maturity (R_o > 2.0%) quite rapidly in the early Late Cretaceous in the central and southern areas. All the source rock transformation ratios (TR) at present are greater than 70% in the P₁ coal and P₁ mudstone layers with TR values approaching 100% in the central and southern areas. The transformation ratios of the P₁ limestone are close to 100% over the entire interval.In the base-case model, a large amount of hydrocarbons appear to have been expelled and migrated into the Shanxi Formation, but only a minor amount was accumulated to form reservoirs. In the model, the Shanxi Formation sandstone layer was set to be homogeneous vertically and there was no regional seal rocks present at the top of the Shanxi Formation. Therefore hydrocarbons could not be trapped effectively with only minor accumulations in some local structural highs where hydrocarbons are trapped both at the top and in the up-dip direction by the adjacent mudstone facies. In contrast, the integrated Sedsim-PetroMod model takes into account of the internal lithological and sedimentary facies heterogeneities within the Shanxi Formation, forming complex contiguous sandstone-mudstone stacking patterns. Hydrocarbons were found to have accumulated in multiple intervals of lithological traps within the Shanxi Formation. The results indicate that lithological distinctions, controlled by sedimentary heterogeneities in three dimensions can provide effective sealing in both the top and up-dip directions for hydrocarbon accumulations, with gas being mainly accumulated near the depocentre where lithological traps usually formed due to frequent oscillations of the lake level.     

“Basin scale” versus “localized” pore pressure/stress coupling - Implications for trap integrity evaluation

In petroleum industry, the difference between pore pressure (P_p) and minimum horizontal stress S_h (termed the seal or retention capacity) is of major consideration because it is often assumed to represent how close a system is to hydraulic failure and thus the maximum hydrocarbon column height that can be maintained. While S_h and P_p are often considered to be independent parameters, several studies in the last decade have demonstrated that S_h and P_p are in fact coupled. However, the nature of this coupling relationship remains poorly understood. In this paper, we explore the influences of the spatial pore pressure distribution on S_h/P_p coupling and then on failure pressure predictions and trap integrity evaluation. With analytical models, we predict the fluid pressure sustainable within a reservoir before failure of its overpressured shale cover. We verify our analytical predictions with experiments involving analogue materials and fluids. We show that hydraulic fracturing and seal breach occur for fluid pressure greater than it would be expected from conventional retention capacity. This can be explained by the impact of the fluid overpressure field in the overburden and the pressure diffusion around the reservoir on the principal stresses. We calculate that supralithostatic pressure could locally be reached in overpressured covers. We also define the retention capacity of a cover (RC) surrounding a fluid source or reservoir as the difference between the failure pressure and the fluid overpressure prevailing in shale at the same depth. In response to a localized fluid pressure rise, we show that the retention capacity does not only depend on the pore fluid overpressure of the overburden but also on the tensile strength of the cover, its Poisson’s ratio, and the depth and width of the fluid source.     

Quantitative modelling of hydrocarbon expulsion and quality grading of tight oil lacustrine source rocks: Case study of Qingshankou 1 member,central depression,Southern Songliao Basin,China

The quality of source rocks plays an important role in the distribution of tight and conventional oil and gas resources. Despite voluminous studies on source rock hydrocarbon generation, expulsion and overpressure, a quality grading system based on hydrocarbon expulsion capacity is yet to be explored. Such a grading system is expected to be instrumental for tight oil and gas exploration and sweet spot prediction. This study tackles the problem by examining Late Cretaceous, lacustrine source rocks of the Qingshankou 1 Member in the southern Songliao Basin, China. By evaluating generated and residual hydrocarbon amounts of the source rock, the extent of hydrocarbon expulsion is modelled through a mass balance method. The overpressure is estimated using Petromod software. Through correlation between the hydrocarbon expulsion and source rock evaluation parameters [total organic carbon (TOC), kerogen type, vitrinite reflectance (R_o) and overpressure], three classes of high-quality, effective and ineffective source rocks are established. High-quality class contains TOC >2%, type-I kerogen, R_o >1.0%, overpressure >7Mpa, sharp increase of hydrocarbon expulsion along with increasing TOC and overpressure, and high expulsion value at R_o >1%. Source rocks with TOC and R_o <0.8%, type-II₂ & III kerogen, overpressure <3Mpa, and low hydrocarbon expulsion volume are considered ineffective. Rocks with parameters between the two are considered effective. The high-quality class shows a strong empirical control on the distribution of tight oil in the Songliao Basin. This is followed by the effective source rock class. The ineffective class has no measurable contribution to the tight oil reserves. Because the hydrocarbon expulsion efficiency of source rocks is controlled by many factors, the lower limits of the evaluation parameters in different basins may vary. However, the classification method of tight source rocks proposed in this paper should be widely applicable.     

Mapping gas hydrate and fluid flow indicators and modeling gas hydrate stability zone (GHSZ) in the Ulleung Basin,East (Japan) Sea: Potential linkage between the occurrence of mass failures and gas hydrate dissociation

The Ulleung Basin, East (Japan) Sea, is well-known for the occurrence of submarine slope failures along its entire margins and associated mass-transport deposits (MTDs). Previous studies postulated that gas hydrates which broadly exist in the basin could be related with the failure process. In this study, we identified various features of slope failures on the margins, such as landslide scars, slide/slump bodies, glide planes and MTDs, from a regional multi-channel seismic dataset. Seismic indicators of gas hydrates and associated gas/fluid flow, such as the bottom-simulating reflector (BSR), seismic chimneys, pockmarks, and reflection anomalies, were re-compiled. The gas hydrate occurrence zone (GHOZ) within the slope sediments was defined from the BSR distribution. The BSR is more pronounced along the southwestern slope. Its minimal depth is about 100 m below seafloor (mbsf) at about 300 m below sea-level (mbsl). Gas/fluid flow and seepage structures were present on the seismic data as columnar acoustic-blanking zones varying in width and height from tens to hundreds of meters. They were classified into: (a) buried seismic chimneys (BSC), (b) chimneys with a mound (SCM), and (c) chimneys with a depression/pockmark (SCD) on the seafloor. Reflection anomalies, i.e., enhanced reflections below the BSR and hyperbolic reflections which could indicate the presence of gas, together with pockmarks which are not associated with seismic chimneys, and SCDs are predominant in the western-southwestern margin, while the BSR, BSCs and SCMs are widely distributed in the southern and southwestern margins. Calculation of the present-day gas-hydrate stability zone (GHSZ) shows that the base of the GHSZ (BGHSZ) pinches out at water depths ranging between 180 and 260 mbsl. The occurrence of the uppermost landslide scars which is below about 190 mbsl is close to the range of the GHSZ pinch-out. The depths of the BSR are typically greater than the depths of the BGHSZ on the basin margins which may imply that the GHOZ is not stable. Close correlation between the spatial distribution of landslides, seismic features of free gas, gas/fluid flow and expulsion and the GHSZ may suggest that excess pore-pressure caused by gas hydrate dissociation could have had a role in slope failures.     

High-resolution P-Cable 3D seismic imaging of gas chimney structures in gas hydrated sediments of an Arctic sediment drift

The newly developed P-Cable 3D seismic system allows for high-resolution seismic imaging to characterize upper geosphere geological features focusing on geofluid expressions (gas chimneys), shallow gas and gas hydrate reservoirs. Seismic imaging of a geofluid system of an Arctic sediment drift at the Vestnesa Ridge, offshore western Svalbard, provides significantly improved details of internal chimney structures from the seafloor to ∼500 m bsf (below seafloor). The chimneys connect to pockmarks at the seafloor and indicate focused fluid flow through gas hydrated sediments. The pockmarks are not buried and align at the ridge-crest pointing to recent, topography-controlled fluid discharge. Chimneys are fuelled by sources beneath the base of gas hydrate stability zone (GHSZ) that is evident at ∼160–170 m bsf as indicated by a bottom-simulating reflector (BSR). Conduit centres that are not vertically straight but shift laterally by up to 200 m as well as discontinuous internal chimney reflections indicate heterogeneous hydraulic fracturing of the sediments. Episodically active, pressure-driven focused fluid flow could explain the hydro-fracturing processes that control the plumbing system and lead to extensive pockmark formation at crest of the Vestnesa Ridge. High-amplitude anomalies in the upper 50 m of the chimney structures suggest formations of near-surface gas hydrates and/or authigenic carbonate precipitation. Acoustic anomalies, expressed as high amplitudes and amplitude blanking, are irregularly distributed throughout the deeper parts of the chimneys and provide evidence for the variability of hydrate and/or carbonate formation in space and time.     

Geochemical evidence for coal-derived hydrocarbons and their charge history in the Dabei Gas Field, Kuqa Thrust Belt, Tarim Basin, NW China

Large to middle-scale thrust structures are important reservoir plays for coal-derived hydrocarbons in the foreland basins of NW China, with both gas and some accompanying oil. In the Dabei Gas Field of the Kuqa Thrust, however, the oil and gas pools are vertically distributed in a quite unique way: (1) liquid oil and some dissolved gas are present in the Dawanqi Anticline with the reservoir at 300-700 m depth, forming the only oil field in the Kuqa Thrust; (2) gas and minor accompanying oil are found in the deep reservoir of the Dabei-1 and Dabei-2 thrust traps around 5000-6000 m depth; (3) an extremely dry gas pool is found in the Dabei-3 thrust trap where the depth of the reservoir is over 7000 m. Geochemical data suggest that the hydrocarbons in the Dawanqi Anticline and the Dabei thrust traps originated from a similar source, i.e. the underlying Jurassic coal measures, with some contribution from Jurassic lacustrine shales. The Jurassic source rocks did not start to generate oil until the Miocene (around the Kangcun Stage), and extended into the Pliocene (the Kuche Stage) with the main gas generation period in the Pliocene (the Kuche Stage) and the Quaternary. Because the traps formed relatively early, the Dabei-1 and Dabei-2 thrusts could trap some of the early generated oils, but most of the early charged oil was redistributed to the shallower Dawanqi Anticline during the Kuche Stage. The Dabei-3 thrust trap formed concurrently with major gas generation and thus could not trap liquid hydrocarbons. The difference in the vertical distribution of the hydrocarbon accumulations in the Dabei Gas Field resulted from a complex interplay of source variability, structural evolution of the basin and thermal maturation.     

Geochemical characteristics of tight gas and gas-source correlation in the Daniudi gas field,the Ordos Basin,China

The molecular composition, stable carbon and hydrogen isotopes and light hydrocarbons of the Upper Paleozoic tight gas in the Daniudi gas field in the Ordos Basin were investigated to study the geochemical characteristics. Tight gas in the Daniudi gas field displays a dryness coefficient (C₁/C_1–5) of 0.845–0.977 with generally positive carbon and hydrogen isotopic series, and the C₇ and C_5–7 light hydrocarbons of tight gas are dominated by methylcyclohexane and iso-alkanes, respectively. The identification of gas origin and gas-source correlation indicate that tight gas is coal-type gas, and the gases reservoired in the Lower Permian Shanxi Fm. (P₁s) and Lower Shihezi Fm. (P₁x) had a good affinity and were derived from the P₁s coal-measure source rocks, whereas the gas reservoired in the Upper Carboniferous Taiyuan Fm. (C₃t) was derived from the C₃t coal-measure source rocks. The molecular and methane carbon isotopic fractionations of natural gas support that the P₁x gas was derived from the P₁s source rocks. The differences of geochemical characteristics of the C₃t gas from different areas in the field suggest the effect of maturity difference of the source rocks rather than the diffusive migration, and the large-scale lateral migration of the C₃t gas seems unlikely. Comparative study indicates that the differences of the geochemical characteristics of the P₁s gases from the Yulin and Daniudi gas fields originated likely from the maturity difference of the in-situ source rocks, rather than the effect of large-scale lateral migration of the P₁s gases.     

Geochemical characteristics and isotopic reversal of natural gases in eastern Kopeh-Dagh,NE Iran

Natural gas samples from two gas fields located in Eastern Kopeh-Dagh area were analyzed for molecular and stable isotope compositions. The gaseous hydrocarbons in both Lower Cretaceous clastic reservoir and Upper Jurassic carbonate reservoir are coal-type gases mainly derived from type III kerogen, however enriched δD values of methane implies presence of type II kerogen related material in the source rock. In comparison Upper Jurassic carbonate reservoir gases show higher dryness coefficient resulted through TSR, while presence of C₁C₅ gases in Lower Cretaceous clastic reservoir exhibit no TSR phenomenon. Carbon isotopic values indicate gas to gas cracking and TSR occurrence in the Upper Jurassic carbonate reservoir, as the result of elevated temperature experienced, prior to the following uplifts in last 33–37 million years. The δ¹³C of carbon dioxide and δ³⁴S of hydrogen sulfide in Upper Jurassic carbonate reservoir do not primarily reflect TSR, as uplift related carbonate rock dissolution by acidic gases and reaction/precipitation of light H₂S have changed these values severely. Gaseous hydrocarbons in both reservoirs exhibit enrichment in C₂ gas member, with the carbonate reservoir having higher values resulted through mixing with highly-mature-completely-reversed shale gases. It is likely that the uplifts have lifted off the pressure on shale gases, therefore facilitated the migration of the gases into overlying horizons. However it appears that the released gases during the first major uplift (33–37 million years ago) have migrated to both reservoirs, while the second migrated gases have only mixed with Upper Jurassic carbonate reservoir gases. The studied data suggesting that economic accumulations of natural gas/shale gases deeper than Upper Jurassic carbonate reservoir would be unlikely.     

Expulsion of Shallow Gas in the Skagerrak—Evidence from Sub-bottom Profiling, Seismic, Hydroacoustical and Geochemical Data

A combined high resolution seismic, sub-bottom profiling, and multi-beam echo-sounding survey in the Skagerrak (Danish sector of the North Sea) together with gas analyses at a station along the profile exhibit the expulsion of gas (mainly methane) and the presence of gas-charged sediments at shallow depth. The echo-soundings yield detailed insight into the distribution and shape of typical sea-floor features associated with gas seepage, such as pockmarks. The pockmarks reach dimensions of 800 m in length, 300 m in width, and 15 m in depth, with the long axis running parallel to the slope of the Norwegian Trench. Processing of the multi-channel high resolution seismic data and the digitally recorded sub-bottom profiler signals indicate an internal compressional velocity of about 1050 m s^-1 within the gas-charged sediments reaching from the sea-floor to a sub-bottom depth of about 23 m. Using the lateral distribution and thickness of the gas-charged sediments in conjunction with a mean concentration of gas of 3000 ppb, the present amount of trapped gas is estimated to be 6·45 × 10¹¹ g CH₄. The flux of methane through the sea-bed into the water column appears to be 7·2 × 10¹⁰ g CH₄ per year. To explain the small difference in size between the methane pool in near-surface sediments and the annual flux through the sea-bed, a constantly high supply of methane from leaking hydrocarbon reservoirs at greater depths has to be active.     

Gas hydrates in shallow deposits of the Amsterdam mud volcano, Anaximander Mountains, Northeastern Mediterranean Sea

We investigated gas hydrate in situ inventories as well as the composition and principal transport mechanisms of fluids expelled at the Amsterdam mud volcano (AMV; 2,025 m water depth) in the Eastern Mediterranean Sea. Pressure coring (the only technique preventing hydrates from decomposition during recovery) was used for the quantification of light hydrocarbons in near-surface deposits. The cores (up to 2.5 m in length) were retrieved with an autoclave piston corer, and served for analyses of gas quantities and compositions, and pore-water chemistry. For comparison, gravity cores from sites at the summit and beyond the AMV were analyzed. A prevalence of thermogenic light hydrocarbons was inferred from average C₁/C₂₊ ratios <35 and δ¹³C-CH₄ values of ?50.6‰. Gas venting from the seafloor indicated methane oversaturation, and volumetric gas–sediment ratios of up to 17.0 in pressure cores taken from the center demonstrated hydrate presence at the time of sampling. Relative enrichments in ethane, propane, and iso-butane in gas released from pressure cores, and from an intact hydrate piece compared to venting gas suggest incipient crystallization of hydrate structure II (sII). Nonetheless, the co-existence of sI hydrate can not be excluded from our dataset. Hydrates fill up to 16.7% of pore volume within the sediment interval between the base of the sulfate zone and the maximum sampling depth at the summit. The concave-down shapes of pore-water concentration profiles recorded in the center indicate the influence of upward-directed advection of low-salinity fluids/fluidized mud. Furthermore, the SO ₄ ^2? and Ba²⁺ pore-water profiles in the central part of the AMV demonstrate that sulfate reduction driven by the anaerobic oxidation of methane is complete at depths between 30 cm and 70 cm below seafloor. Our results indicate that methane oversaturation, high hydrostatic pressure, and elevated pore-water activity caused by low salinity promote fixing of considerable proportions of light hydrocarbons in shallow hydrates even at the summit of the AMV, and possibly also of other MVs in the region. Depending on their crystallographic structure, however, hydrates will already decompose and release hydrocarbon masses if sediment temperatures exceed ca. 19.3°C and 21.0°C, respectively. Based on observations from other mud volcanoes, the common occurrence of such temperatures induced by heat flux from below into the immediate subsurface appears likely for the AMV.     

琼东南盆地深水区崖城组生成天然气的化学动力学及其应用

The natural gas generation process is simulated by heating source rocks of the Yacheng Formation, including the onshore-offshore mudstone and coal with kerogens of Type II_2-III in the Qiongdongnan Basin. The aim is to quantify the natural gas generation from the Yacheng Formation and to evaluate the geological prediction and kinetic parameters using an optimization procedure based on the basin modeling of the shallow-water area. For this, the hydrocarbons produced have been grouped into four classes(C_1, C_2, C_3 and C_(4-6)). The results show that the onset temperature of methane generation is predicted to occur at 110℃ during the thermal history of sediments since 5.3 Ma by using data extrapolation. The hydrocarbon potential for ethane, propane and heavy gaseous hydrocarbons(C_(4-6)) is found to be almost exhausted at geological temperature of 200℃ when the transformation ratio(TR) is over 0.8, but for which methane is determined to be about 0.5 in the shallow-water area. In contrast, the end temperature of the methane generation in the deep-water area was over 300℃ with a TR over 0.8. It plays an important role in the natural gas exploration of the deep-water basin and other basins in the broad ocean areas of China. Therefore, the natural gas exploration for the deep-water area in the Qiongdongnan Basin shall first aim at the structural traps in the Ledong, Lingshui and Beijiao sags, and in the forward direction of the structure around the sags, and then gradually develop toward the non-structural trap in the deep-water area basin of the broad ocean areas of China.     

Hydrocarbon migration and accumulation of the Suqiao buried-hill zone in Wen'an Slope,Jizhong Subbasin,Bohai Bay Basin,China

The hydrocarbon migration and accumulation of the Suqiao deep buried-hill zone, in the Jizhong Subbasin, the Bohai Bay Basin, eastern China, was investigated from the perspective of paleo-fluid evidence by using fluid inclusions, quantitative fluorescence techniques (QGF), total scanning fluorescence method (TSF) and organic geochemical analysis. Results show that the current condensate oil-gas reservoirs in the study area once were paleo-oil reservoirs. In addition, the reservoirs have experienced at least two stages of hydrocarbon charge from different sources and/or maturities. During the deposition of the Oligocene Dongying Formation (Ed), the deep Ordovician reservoirs were first charged by mature oils sourced from the lacustrine shale source rocks in the fourth member of Shahejie and Kongdian Formations (Es₄+Ek), and then adjusted at the end of Ed period subsequently by virtue of the tectonic movement. Since the deposition of the Neogene Minghuazhen Formation (Nm), the reservoirs were mainly charged by the gas that consisted of moderate to high-maturity condensate and wet gas sourced from the Es₄+Ek lacustrine shale source rocks and mature coal-derived gas sourced from the Carboniferous-Permian (C-P) coal-bearing source rocks. Meanwhile, the early charged oil was subjected to gas flushing and deasphalting by the late intrusion of gas. The widely distributed hydrocarbon inclusions, the higher QGF Index, and FOI (the frequency of oil inclusions) values in both gas-oil and water zone, are indicative of early oil charge. In addition, combined with the homogenization temperatures of the fluid inclusions (<160 °C) and the existence of solid-bitumen bearing inclusions, significant loss of the n-alkanes with low carbon numbers, enrichments of heavier components in crude oils, and the precipitation of asphaltene in the residual pores suggest that gas flushing may have played an important role in the reservoir formation.     

Geochemistry,origin and accumulation of natural gases in the deepwater area of the Qiongdongnan Basin,South China Sea

The Qiongdongnan Basin, South China Sea has received huge thickness (>12 km) of Tertiary-Quaternary sediments in the deepwater area to which great attention has been paid due to the recent discoveries of the SS22-1 and the SS17-2 commercial gas fields in the Pliocene-Upper Miocene submarine canyon system with water depth over 1300 m. In this study, the geochemistry, origin and accumulation models of these gases were investigated. The results reveal that the gases are predominated by hydrocarbon gases (98%–99% by volume), with the ratio of C₁/C_1-5 ranging from 0.92 to 0.94, and they are characterized by relatively heavy δ¹³C₁ (−36.8‰ to −39.4‰) and δD_CH4 values (−144‰ to −147‰), similar to the thermogenic gases discovered in the shallow water area of the basin. The C_5-7 light hydrocarbons associated with these gases are dominated by isoparaffins (35%–65%), implying an origin from higher plants. For the associated condensates, carbon isotopic compositions and high abundance of oleanane and presence of bicadinanes show close affinity with those from the YC13-1 gas field in the shallow water area. All these geochemical characteristics correlate well with those found in the shales of the Oligocene Yacheng Formation in the Qiongdongnan Basin. The Yacheng Formation in the deepwater area has TOC values in the range of 0.4–21% and contains type II_b–III gas-prone kerogens, indicating an excellent gas source rock. The kinetic modeling results show that the δ¹³C₁ values of the gas generated from the Yacheng source rock since 3 or 4 Ma are well matched with those of the reservoir gases, indicating that the gas pool is young and likely formed after 4 Ma. The geologic and geochemical data show that the mud diapirs and faults provide the main pathways for the upward migration of gases from the deep gas kitchen into the shallow, normally pressured reservoirs, and that the deep overpressure is the key driving force for the vertical and lateral migration of gas. This gas migration pattern implies that the South Low Uplift and the No.2 Fault zone near the deepwater area are also favorable for gas accumulation because they are located in the pathway of gas migration, and therefore more attention should be paid to them in the future.