the fate and accumulation of bromide during playa salt deposition an example from lake frome south australia an advectivn diffusion model describing the distribution of br in porewaters underlying an accumulating deposit of halite on a playa lake can be used to predict the evolving composition of the accumulating salt growing as a result of evaporation the br cl ratio of the accumulating halite is proportional to the concentration or br at the surface of the brine body from which it is growing the evolution of interstitial br and therefore the composition of the accumulating salt is a function of 1 the diffusion coefficient of br in the brine saturated sediment 2 the advective velocity of the interstitial water 3 the initial concentration of br and cl at the onset of evaporation and 4 the distribution coefficient of br into the accumulating salt all of which can be estimated for the sediments and brines of lake frome south australia at lake frome the model is used to estimate mean evaporation rates for the salt covered surfaces which are found to be between 0 5 and 3 0 cm y these rates are lower than the rates estimated for the salt free surfaces of the lake by allison and barnes 1985 but are consistent with the expectation that groundwater input and therefore evaporation rates will be focused at the salt free lake margins rather than at the salt covered central regions of the playa and that the surface albedo of the salt covered zones will reduce energy penetration to the sediment and thus evaporation

diagenesis in north sea hpht clastic reservoirs consequences for porosity and overpressure prediction upper jurassic clastic reservoirs of the fulmar formation in the central north sea possess anomalously high porosities for their present day depth of burial reservoirs with the highest overpressures have the highest porosities possess less macroquartz cement and have significant secondary porosity quartz cementation in hpht high pressure high temperature reservoirs has been inhibited by a combination of factors high overpressure limited fluid movement presence of early grain coating cements high pore fluid salinity and possibly petroleum migration secondary porosity has contributed to reservoir quality with an average of 4vol extra porosity created quantitative prediction of porosity would require an improved depositional model for the fulmar accurate thermal and pressure modelling and detailed knowledge of field filling and leakage histories theoretical calculations indicate that diagenetic reactions occurring in the fulmar formation smectite illitisation and quartz cementation did not generate significant overpressure because seal permeabilities were too high and the rate of volume increase associated with the reactions too small therefore diagenetic reactions can effectively be ignored when modelling overpressure generation in the central north sea although cementation will affect rock permeability and rates of fluid dissipation

establishing resolution limits for tectonic subsidence curves by forward basin modelling abstract a forward model was used to study the relationship between gravitational compaction and tectonic subsidence in an idealized one dimensional sedimentary basin gravitational compaction was modelled by a non linear partial differential equation that gives the sediment porosity as a function of time and burial depth the sediments were described in terms of soil mechanics laws for mechanical compressibility and permeability the sedimentation rate appeared as a boundary condition at the depositional surface tectonic subsidence was coupled to the compaction model via an isostatic balance based on airy s hypothesis parameter studies showed that changes in the sedimentation rate and in the sediment compressibility can lead to variations from 454 to 781 m in the subsidence for sediment thicknesses in the range 6 9 7 9 km the forward model was used to assess how well standard backstripping methods reconstructed subsidence history from present day porosity versus depth data standard backstripping can bias the tectonic subsidence by 100 200 m comparable with inferred eustatic variations this bias results because the porosity depends not only on burial depth but also on time by using deterministic models to describe gravitational compaction mechanical properties can be used to better constrain compaction history thus improving the accuracy of reconstructed tectonic subsidence curves

determining vertical leakage from the great artesian basin australia through up scaling field estimates of phreatic evapotranspiration summary understanding the water balance of large groundwater systems is fundamental for the sustainable management of the resource the vertical leakage i e discharge to upper aquifers or the unconfined water table component of the great artesian basin gab is an example of a poorly constrained but large component of the water balance of australia s largest groundwater resource field estimates of phreatic evapotranspiration et were made at discharge zones along the southwestern margin of the gab using eddy covariance station and micro lysimeter measurements and inversion of chloride isotope soil profile measurements the field estimates were assigned to three major landforms associated with areas of increasingly higher evaporative discharge and progressively decreasing depths to the water table these landforms were mapped using remote sensing and digital elevation data with characteristically higher soil moisture salt precipitation and lower surface temperature compared to areas distal to discharge zones based on the field measurements broad ranges of phreatic et 0 5 10 10 100 and 100 300 mm y 1 were assigned to the major land types the higher phreatic et discharge zones mapped by supervised classification of satellite data are 8 28 of the total regional vertical leakage component estimated by numerical modelling of the gab in comparison the higher discharge zones estimated by landform mapping are 73 251 of the total vertical leakage component estimated by modelling the mapped distribution of the high discharge areas has important implications for modelling of the gab in the western sub basin most of the estimated recharge can be accounted for by phreatic et in the high discharge zones located around the basin margins implying that vertical leakage rates distal to the margins are very low and that discharge may exceed current recharge in contrast the results for the eastern sub basin suggest that vertical leakage rates around the south australian portion of the basin margin are low and that more of the vertical leakage component in the eastern sub basin is occurring distal to the basin margins consequently the pathways for vertical leakage in the eastern sub basin are likely to be more complex than for the western sub basin

permian sedimentary tuff tight reservoirs in the santanghu basin nw china abstract sedimentary tuffs comprise important tight oil reservoirs in the middle permian tiaohu formation in the santanghu basin this paper describes three research advances made on these reservoirs 1 there are many sets of sedimentary tuff in the second member of the tiaohu formation and they are the sweet section for tight oil exploration vitric crystal vitric and argillaceous tuffs are the main reservoir types of which the first two are more favorable 2 a model was established to show how the volcanic edifice controls the type and distribution of the volcanic lacustrine tuff deposition the crystal vitric tuff is distributed in the lacustrine deposits nearest to the volcanic crater and the vitric tuff is distributed on both sides of the active volcanic belt a certain distance from the crater and this is the most favorable distribution area for sedimentary tuff later devitrification resulted in formation of a large number of micro pores and this is the main reason for the presence of favorable reservoirs 3 the sedimentary tuff reservoir has undergone successive geological processes from formation of secondary dissolution pores then hydrocarbon charge and accumulation to compaction the tight oil accumulation is the result of the coupling of the diagenetic evolution of the tuff in the tiaohu formation and the hydrocarbon generation and charging from the shale in the lucaogou formation

hydrochemical and isotopic characteristics of groundwater in the yanqi basin of xinjiang province northwest china in this study hydrochemical and isotope investigations were conducted in the yanqi basin to determine the chemical composition and to gain insight into the groundwater recharge process in the yanqi basin it mainly used hydrochemistry environmental isotopes and a series of comprehensive data interpretation e g statistics ionic ratios and piper diagram to obtain a better understanding of the functioning of the system the following hydrochemical processes were identified as the main factors controlling the water quality of the groundwater system weathering of silicate minerals dissolution ion exchange and to a lesser extent evaporation which seemed to be more pronounced down gradient of the flow system as groundwater flows from the recharge to discharge areas chemical patterns evolve in the order of ca2 hco3 ca2 mg2 hco3 to ca2 mg2 cl so4 2 na k cl so4 2 and na cl according to lithology the environmental isotope 18o 2h 3h measurements further revealed that precipitation was the main recharge source for the groundwater system some local values indicated high levels of evaporation tritium and cfc analysis were used to estimate the ages of the different groundwater the tritium values of the groundwater samples varied from 2 82 to 29 7 tu the age of the groundwater at depths of 120 m is about 30 50 years cfc values obtained for six samples to determine groundwater age the age of the groundwater is about 20 50 years

remotely sensed regional scale evapotranspiration of a semi arid great basin desert and its relationship to geomorphology soils and vegetation abstract landsat thematic mapper data are used to estimate instantaneous regional scale surface water and energy fluxes in a semi arid great basin desert of the western united states results suggest that it is possible to scale from point measurements of environmental state variables to regional estimates of water and energy exchange this research characterizes the unifying thread in the classical climate topography soil vegetation relation the surface water and energy balance through maps of the partitioning of energy throughout the landscape the study was conducted in goshute valley of northeastern nevada which is characteristic of most faulted graben valleys of the basin and range province of the western united states the valley comprises a central playa and lake plain bordered by alluvial fans emanating from the surrounding mountains the distribution of evapotranspiration et is lowest in the middle reaches of the fans where the water table is deep and plants are small resulting in low evaporation and transpiration highest et occurs in the center of the valley particularly in the playa where limited to no vegetation occurs but evaporation is relatively high because of a shallow water table and silty clay soil capable of large capillary movement intermediate values of et are associated with large shrubs and is dominated by transpiration

the puguang gas field new giant discovery in the mature sichuan basin southwest china the giant puguang gas field with a proven original in place gas volume of 350 109 m3 12 36 tcfg was discovered in 2003 in the eastern sichuan fold thrust belt of the mature sichuan basin southwest china the field is a combination structural stratigraphic trap closed by lateral depositional change and fault closure the trap evolved from a paleo oil reservoir originating in the triassic jurassic the entrapment of thermal gas which was derived from lower middle silurian and permian source rocks occurred during deep burial in the jurassic cretaceous tertiary quaternary compression transformed the paleotrap into the present gas reservoir gas is contained in the lower triassic feixianguan and the upper permian changxing reservoirs which consist predominantly of dolomitized oolites deposited in shelf and platform margin shoal and backreef environments reservoir quality is characterized by porosity of 1 29 and permeability of 0 01 9664 md with buried depth greater than 5000 m 16 400 ft the discovery of the puguang field exemplifies the successful application of a new play concept and new technology in a mature basin the discovery resulted from a shift in exploration strategy from structures to stratigraphic traps in reef and shoal dolomites and benefited from advanced high resolution seismic techniques the discovery will not only broaden the exploration scope in the sichuan basin but also provide an excellent analog for exploration in other fold thrust belts worldwide

origin of overpressure and pore pressure prediction in the baram province brunei accurate pore pressure prediction is critical in hydrocarbon exploration and is especially important in the rapidly deposited tertiary baram delta province where all economic fields exhibit overpressures commonly of high magnitude and with narrow transition zones a pore pressure database was compiled using wireline formation interval tests drillstem tests and mud weights from 157 wells in 61 fields throughout brunei overpressures are observed in 54 fields both in the inner shelf deltaic sequences and in the underlying prodelta shales porosity vs vertical effective stress plots from 31 fields reveal that overpressures are primarily generated by disequilibrium compaction in the prodelta shales but have been generated by fluid expansion in the inner shelf deltaic sequences however the geology of brunei precludes overpressures in the inner shelf deltaics being generated by any conventional fluid expansion mechanism e g kerogen to gas maturation and we propose that these overpressures have been vertically transferred into reservoir units via faults from the prodelta shales sediments overpressured by disequilibrium compaction exhibit different physical properties to those overpressured by vertical transfer and hence different pore pressure prediction strategies need to be applied in the prodelta shales and inner shelf deltaic sequences sonic and density log data detect overpressures generated by disequilibrium compaction and pore pressures are accurately predicted using an eaton exponent of 3 0 sonic log data detect vertically transferred overpressures even in the absence of a porosity anomaly and pore pressures are reasonably predicted using an eaton exponent of 6 5

constraining tectonic compression processes by reservoir pressure evolution overpressure generation and evolution in the kelasu thrust belt of kuqa foreland basin nw china abstract the kuqa foreland basin kfb immediately south of the south tianshan mountains is a major hydrocarbon producing basin in west china the kelasu thrust belt in the basin is the most favorable zone for hydrocarbon accumulations widespread overpressures are present in both the cretaceous and paleogene reservoirs with pressure coefficients up to 2 1 the tectonic compression process in kfb resulted from the south tianshan mountains uplift is examined from the viewpoint of the overpressure generation and evolution in the kelasu thrust belt the overpressure evolution in the reservoir sandstones were reconstructed through fluid inclusion analysis combined with pvt and basin modeling overpressures at present day in the mudstone units in the kelasu thrust belt and reservoir sandstones of the dabei gas field and the keshen zone are believed to have been generated by horizontal tectonic compression both disequilibrium compaction and horizontal tectonic compression are thought to contribute to the overpressure development at present day in the reservoir of the kela 2 gas field with the reservoir sandstones showing anomalously high primary porosities and low densities from wireline log and core data the overpressure evolution for the cretaceous reservoir sandstone in the kelasu thrust belt evolved through four stages a normal hydrostatic pressure 12 5 ma a rapidly increasing overpressure 5 3 ma an overpressure release 3 1 64 ma and overpressure preservation 1 64 0 ma overpressure developed in the second stage 5 3 ma was generated by disequilibrium compaction as tectonic compression due to the uplift of the tianshan mountains acted at the northern monocline of kfb from 5 ma to 3 ma which provided abundant sediments for the kfb and caused the anomalously high sedimentation rate during the n2k deposition from 3 ma to 1 64 ma the action of tectonic compression extended from the northern monocline to the kelasu thrust belt and returned to the northern monocline of kfb from 1 64 ma to present day therefore the horizontal tectonic compression was the dominant overpressure mechanism for the overpressure generation in the third stage 3 1 64 ma and overpressure caused by disequilibrium compaction from 5 ma to 3 ma was only preserved in the kela 2 gas field until present day

barnett shale gas production fort worth basin issues and discussion newark east barnett shale field fort worth basin texas is currently the most productive gas field in texas in terms of daily production and is growing at an annual rate of more than 10 however despite the fact that the barnett play has been studied intensely by very capable geologists and engineers from several companies over a period of many years there continues to be several misunderstandings concerning fundamental factors controlling the success of the barnett play of north texas barnett gas production is poorer in areas near faults and structural flexures anticlines and synclines fractures which are most abundant in these structural settings are detrimental to barnett production open natural fractures are rare in the barnett and have little or nothing to do with barnett productivity in areas where barnett shale is thermally mature with respect to gas generation it is slightly overpressured about 0 52 psi ft 11 76 kpa m limestone beds within the barnett formation are the product of debris flows that originated on a carbonate shelf to the north of the present basin center it appears that the barnett can be used as an exploration model for other basins especially analogous basins of the ouachita trend the history of the development of the barnett reservoir in north texas provides an excellent example of how persistence can lead to success in nonconventional gas plays

major and trace element geochemistry in zeekoevlei south africa a lacustrine record of present and past processes this study reports a multi parameter geochemcial investigation in water and sediments of a shallow hyper eutrophic urban freshwater coastal lake zeekoevlei in south africa zeekoevlei receives it

identifying fluvial recharge and artesian upwards leakage contributions to arid zone shallow unconfined groundwater evaporation losses from unconfined groundwater can form an important part of the water balance of arid zone groundwater systems however in artesian groundwater systems the discrimination between artesian leakage and surface recharge contributions to the unconfined water table is required we use hydrochemical analysis techniques and isotopic data to investigate the provenance of unconfined groundwater in zones of artesian discharge along the margin of the great artesian basin gab of australia forward modelling of evapoconcentration and use of trilinear plots identified unconfined groundwater that was largely derived from fluvial recharge compared to upwards artesian leakage particularly in areas where the artesian groundwater had a na hco3 cl composition in contrast to the na cl so4 composition more typical of arid zone meteoric recharge mixing models combined with forward evapoconcentration models confirmed that the contribution of artesian groundwater was minimal in areas of na cl so4 unconfined groundwater underlain by na hco3 cl artesian groundwater however the evaporation modelling was still useful in identifying probable artesian versus meteoric contributions from na cl so4 composition artesian groundwater stable isotope data were consistent with the unconfined groundwater being evapoconcentrated from the artesian groundwater end member and were unable to discriminate between contributions from fluvial recharge and artesian discharge the hydrochemical analysis techniques can assist in water balance studies of aquifers with na hco3 cl composition groundwater discharging into semi arid and arid environments in addition to identifying areas of local fluvial recharge

geochemical characteristics and origin of natural gas from wufeng longmaxi shales of the fuling gas field sichuan basin china abstract as the first giant shale gas field in china the fuling gas field has recently been regarded as one of the most important regions for natural gas exploration and production in the sichuan basin however the origin of natural gas from upper ordovician wufeng and the bottom of lower silurian longmaxi wl shales in the fuling gas field is poorly understood to limit a comprehensive understanding of gas generation accumulation and exploration in this work based on molecular and stable carbon isotopic composition of a total of 24 gas samples from five shale gas wells in the fuling field we analyzed the geochemical characteristics and gas origin and discussed the cause for the geochemical anomalies carbon isotopic reversals molecular composition results show that gases from the fuling gas field are dry and mainly composed of methane 97 9 98 9 with a very low level of ethane c2h6 propane c3h8 and non hydrocarbon gases mainly co2 and n2 these dry gases are classified as oil associated gas and mainly derived from secondary cracking due to the lack of gas samples across a maturation gradient from immature to late mature the wl gases in the fuling field show an unclear evolution trend between the 13c2 and wetness values however all these samples are located in the isotopic reversal zone carbon isotopes of gaseous alkanes clearly display full isotopic reversals 13c1 13c2 13c3 which is indicative of a relatively high thermal maturity and consistent with the measured vitrinite reflectance and modeled values 3 0 ro the observed complete carbon isotopic reversals in the wl gases are caused by a combination of several mechanisms in which isotope exchange at high temperature is the primary controlling factor other secondary factors include rayleigh type fractionation of c2h6 and c3h8 secondary cracking and gas diffusion mixing of gases at different thermal maturity levels

families of miocene monterey crude oil seep and tarball samples coastal california biomarker and stable carbon isotope ratios were used to infer the age lithology organic matter input and depositional environment of the source rocks for 388 samples of produced crude oil seep oil and tarballs to better assess their origins and distributions in coastal california these samples were used to construct a chemometric multivariate statistical decision tree to classify 288 additional samples the results identify three tribes of 13c rich oil samples inferred to originate from thermally mature equivalents of the clayey siliceous carbonaceous marl and lower calcareous siliceous members of the monterey formation at naples beach near santa barbara an attempt to correlate these families to rock extracts from these members in the nearby cost continental offshore stratigraphic test ocs cal 78 164 well failed at least in part because the rocks are thermally immature geochemical similarities among the oil tribes and their widespread distribution support the prograding margin model or the banktop slope basin model instead of the ridge and basin model for the deposition of the monterey formation tribe 1 contains four oil families having geochemical traits of clay rich marine shale source rock deposited under suboxic conditions with substantial higher plant input tribe 2 contains four oil families with traits intermediate between tribes 1 and 3 except for abundant 28 30 bisnorhopane indicating suboxic to anoxic marine marl source rock with hemipelagic input tribe 3 contains five oil families with traits of distal marine carbonate source rock deposited under anoxic conditions with pelagic but little or no higher plant input tribes 1 and 2 occur mainly south of point conception in paleogeographic settings where deep burial of the monterey source rock favored petroleum generation from all three members or their equivalents in this area oil from the clayey siliceous and carbonaceous marl members tribes 1 and 2 may overwhelm that from the lower calcareous siliceous member tribe 3 because the latter is thinner and less oil prone than the overlying members tribe 3 occurs mainly north of point conception where shallow burial caused preferential generation from the underlying lower calcareous siliceous member or another unit with similar characteristics in a test of the decision tree 10 tarball samples collected from beaches in monterey and san mateo counties in early 2007 were found to originate from natural seeps representing different organofacies of monterey formation source rock instead from one anthropogenic pollution event the seeps apparently became more active because of increased storm activity

origin of quartz cement in the tirrawarra sandstone southern cooper basin south australia abstract quartz cement is the most abundant authigenic mineral in the fluvio deltaic tirrawarra sandstone and plays an important role in controlling reservoir quality quartz cement ranges from 0 to 19 and is controlled by the original sandstone composition petrographic fluid inclusion electron microprobe and cathodoluminescence cl data from the quartz cement indicate multiple stages of cementation at different temperatures and suggest more than one silica source cl observations indicate up to six stages of quartz cement in some samples the stages of quartz cement can be classified into three zones an innermost zone of brown luminescing cement z1 a middle zone of bright blue luminescing cement z2 and an outer zone of brown luminescing cement z3 dead oil or bitumen is trapped b tween z2 and z3 indicating that z3 formed after oil migration commenced measurements of homogenization temperatures from fluid inclusions in quartz overgrowths indicate that quartz cement precipitated over a temperature range of 65 to 130 c z1 quartz cement formed between 65 and 80 c and z2 cement was precipitated between 80 c and 100 c z3 quartz cement formed later at temperatures around 130 c microprobe analysis shows a consistent variation in aluminum between each quartz cement zone the average aluminum content for z1 z2 and z3 is respectively 237 538 and 58 ppm fluid inclusion precipitation temperatures and aluminum content have been used to help identify the silica sources for different zones of cement a likely source of silica for z1 quartz cement is early alteration of feldspar grains the bright blue cl color in the z2 quartz cement is related to its high aluminum content the source of silica for this cement is likely to have been late dissolution of feldspar grains by acidic fluids generated during kerogen maturation late quartz cement z3 has the lowest aluminum content which is similar to that of detrital quartz grains in the tirrawarra sandstone consi ering the temperature of precipitation very low aluminum content and the presence of z3 cement in facies prone to stylolitization the silica source for the cement is likely to have been pressure solution of detrital quartz at stylolites and grain contacts

oil retention and porosity evolution in organic rich shales petroleum is retained in shales either in a sorbed state or in a free form within pores and fractures in shales with oil resource potential organic matter properties i e richness quality and thermal maturity control oil retention in general in gas shales organic pores govern gas occurrence although some pores may originate via secondary cracking reactions it is still largely unclear as to how these pores originate here we present case histories mainly for two classic shales the mississippian barnett shale texas and the toarcian posidonia shale lower saxony germany in both cases shale intervals enriched in free oil or bitumen are not necessarily associated with the layers richest in organic matter but are instead associated with porous biogenic matrices however for the vast bulk of the shale hydrocarbon retention and porosity evolution are strongly related to changes in kerogen density brought about by swelling and shrinkage as a function of thermal maturation secondary organic pores can form only after the maximum kerogen retention swelling ability is exceeded at tmax the temperature at maximum rate of petroleum generation by rock eval pyrolysis around 445 c 833 f approximately 0 8 vitrinite reflectance shrinkage of kerogen itself leads to the formation of organic nanopores and associated porosity increase in the gas window

a 48 m y history of fracture opening temperature and fluid pressure cretaceous travis peak formation east texas basin quartz cement bridges across opening mode fractures of the cretaceous travis peak formation provide a textural and fluid inclusion record of incremental fracture opening during the burial evolution of this low porosity sandstone incremental crack seal fracture opening is inferred based on the banded structure of quartz cement bridges consisting of up to 700 cement bands averaging 5 m in thickness as observed with scanning electron microscope cathodoluminescence crack seal layers contain assemblages of aqueous two phase fluid inclusions based on fluid inclusion microthermometry and raman microprobe analyses we determined that these inclusions contain methane saturated brine trapped over temperatures ranging from 130 c to 154 c using textural crosscutting relations of quartz growth increments to infer the sequence of cement growth we reconstructed the fluid temperature and pore fluid pressure evolution during fracture opening in combination with published burial evolution models this reconstruction indicates that fracture opening started at ca 48 ma and above hydrostatic pore fluid pressure conditions and continued under steadily declining pore fluid pressure during partial exhumation until present times individual fractures opened over an 48 m y time span at rates of 16 23 m m y these rates suggest that fractures can remain hydraulically active over geologically long times in deep basinal settings

polyphase thermal evolution in the infra cambrian ara group south oman salt basin as deduced by maturity of solid reservoir bitumen petrographic and organic geochemical analyses on solid reservoir bitumen from the late precambrian to early cambrian ara group indicate polyphase thermal evolution in the south oman salt basin sosb the ara group constitutes a complex petroleum system in the deep subsurface 3 5 km of interior oman salt diapirs encase isolated partly highly overpressured carbonate bodies intra salt stringers which represent a predominantly self charging hydrocarbon system a large number of stringer cores show that reservoir quality is decreased by the presence of solid reservoir bitumen by using different microscopy techniques this solid reservoir bitumen has been identified within pores pore throats and microfractures of the carbonates solid bitumen reflectance measurements brr were converted to vitrinite reflectance vrr using a new improved calibration vitrinite reflectance geothermometry shows that maximum paleo temperatures have a highly heterogeneous distribution paleo temperatures of 380 c were obtained from coke like solid reservoir bitumen which most likely formed from thermal cracking of oil in our model this process is related to hydrothermal fluids deriving from deeper pre salt strata of the sosb which entered the intra salt carbonate stringers during times of basement tectonic activity via hydrofractures this caused the formation of high maturities pyrobitumens in close vicinity to the fractures and precipitation of migrabitumens with increasing distance to the ht source which is supported by the geochemical composition of the solid reservoir bitumens the influx of these fluids into the carbonate stringers is considered to represent a major contribution to their strong overpressures 2007 elsevier ltd all rights reserved

differential evolution and the influencing factors of low maturity terrestrial shale with different types of kerogen a case study of a jurassic shale from the northern margin of qaidam basin china abstract the jurassic terrestrial shale on the northern margin of qaidam basin is characterized by high contents of organic matter but low maturity resulting in a lack of further research on shale gas in this area to better understanding the shale gas potential of organic matter with different types we conducted thermal maturity experiment of hydrocarbon generation from different kerogen types of low mature shales under closed conditions the results show that type ii and type iii kerogen have experienced similar hydrocarbon generation stages but they differ in the hydrocarbon generation interval and evolution process between liquid hydrocarbon and gaseous hydrocarbon compared with type iii kerogen type ii kerogen is characterized by a low initial temperature at each evolutionary stage and wide temperature range which caused the overall evolution of type iii kerogen lagged behind that of type ii kerogen the differential evolutions mainly result from the differences in hydrocarbon generation mechanism hydrocarbon generation activation energy and kerogen macerals among different kerogen types we summarized the evolution model of type ii and type iii kerogen based on the characteristics of kerogen in hydrocarbon generation carbon isotope change pore development and other aspects this work can provide theoretical and data support for reconstructing the hydrocarbon generation process of terrestrial shale gas investigating the hydrocarbon generation mechanism and predicting the hydrocarbon resources of terrestrial shale oil and gas on the northern margin of qaidam basin and even china

oil generation as the dominant overpressure mechanism in the cenozoic dongying depression bohai bay basin china the dongying depression in the bohai bay basin is a young prolific oil producing basin in china the gray to black mudstones calcareous mudstones and oil shales of the eocene shahejie formation es3 and es4 are the major source rocks that are primarily dominated by type i kerogens with a high total organic carbon of up to 18 6 the es3 interval is characterized by a sedimentation rate of up to 500 m m y widespread overpressures are present in the eocene es3 and es4 intervals in the depression with pressure coefficients up to 1 99 from drillstem tests among the sonic resistivity and density logs only the sonic log displays an obvious response to the overpressure from which the top of the overpressure can be clearly identified acoustic traveltime versus effective vertical stress analysis of more than 300 wells in the dongying depression suggests that the acoustic traveltime of the normally pressured and overpressured mudstones is reduced with increasing vertical effective stress pore pressures are accurately predicted in the dongying depression using an eaton 1972 exponent of 2 0 by comparing the predicted pressure coefficients with measured pressure coefficients disequilibrium compaction has been previously proposed as the sole cause of the high magnitude overpressures in the eocene strata of the dongying depression because of rapid deposition of fine grained sediments however our data indicate that the overpressures are caused by oil generation from the source rocks within the es3 and es4 intervals the overpressured sediments display a normal compaction as evidenced from the overpressured mudstones exhibiting no anomalously low density the apparent lack of correlation between mudstone densities and effective vertical stress and the overpressured reservoir sandstones showing no anomalous high matrix porosities or anomalous geothermal gradient the depths to the top of the overpressure intervals range from 2000 to 3000 m 6562 9843 ft following closely source rock depths all the overpressured reservoirs and source rocks have a minimum temperature of approximately 87c and overpressured source rocks generally have vitrinite reflectance ro values of 0 6 or higher overpressures are not found in the strata within which the ro values are less than 0 5 the overpressured reservoirs in the es3 and es4 intervals are predominantly oil saturated or oil bearing organic rich source rocks with overpressures are capable of generating hydrocarbons and thus can maintain an abnormally high pressure the calcite precipitation in the calcareous mudstones may have caused a significant reduction in porosity and permeability to form an effective pressure seal the presence of widespread microfractures in the source rocks may relate to episodic expulsion of hydrocarbons or overpressure dissipation overpressures in the reservoir rocks are generated by the fluid transmission from the overpressured source rocks through active faulting and fracturing

characteristics and origin of the gas and condensate in the yinggehai basin offshore south china sea evidence for effects of overpressure on petroleum generation and migration three superimposed pressure systems have developed in the yinggehai basin the strongly overpressured rocks have abnormally low vitrinite reflectance ro and rock eval tmax values and display abnormal c15 hydrocarbon distributions such organic maturity anomalies were confirmed to be the result of overpressure retardation commercial gas fields with carbon dioxide content up to 93 and gas shows with nitrogen content more than 50 have been found in the basin methane and carbon dioxide dominated gases have low c2 hydrocarbon contents less than 4 and heavy methane 13c and d values and the associated condensates have high diamondoid indices and very low c25 saturated hydrocarbon concentration at the same time the methane and carbon dioxide dominated gases have high branched and cyclic light hydrocarbon contents and associated condensates have abnormally low heptane and isoheptane values low sterane isomerization values and abnormally high concentrations of isoprenoid hydrocarbons relative to adjacent n paraffins these distinct characteristics seem to result from the effects of overpressure on both hydrocarbon generation and migration

a compositional classification for grain assemblages in fine grained sediments and sedimentary rocks reply abstract a tripartite compositional classification is proposed for sediments and sedimentary rocks that have grain assemblages with greater than 50 percent of a weight or volume of particles smaller than 62 5 m 4 phi tarl terrigenous argillaceous contains a grain assemblage dominated by more than 75 percent of particles of extrabasinal derivation including grains derived from continental weathering and also volcanogenic debris carl calcareous argillaceous contains less than 75 percent of particles of extrabasinal derivation debris and among its intrabasinal grains contains a preponderance of biogenic carbonate particles including carbonate aggregates sarl siliceous argillaceous contains less than 75 percent of particles of extrabasinal derivation and contains a preponderance of biogenic siliceous particles over carbonate grains these three classes of fine grained particulate sediments and rocks effectively separate materials that have distinct depositional settings and systematic contrasts in organic matter content and minor grain types in the subsurface the grain assemblages that define these classes follow contrasting and predictable diagenetic pathways that have significant implications for the evolution of bulk rock properties and thus assigning a fine grained rock to one of these classes is an important first step for predicting its economic and engineering qualities for purposes of description these three class names can be joined to modifier terms denoting rock texture more precise compositional divisions specific grain types of notable importance and diagenetic features

control of facies maturation and primary migration on biomarkers in the barnett shale sequence in the marathon 1 mesquite well texas abstract a great deal is known about the genetic relationships between biomarkers and their biogenic precursors in organic rich rocks the same is true of the way in which biomarker compound ratios change during maturation on the other hand very little is known about whether a crude oil can fully retain its inherent compositional ancestry during expulsion from a source rock thanks to shales being characterized in great detail for their unconventional resource potential new information is gradually coming to light here we report on observations in biomarker geochemistry of a thermally mature core of the barnett shale in which organofacies and maturity are essentially the same but where intraformational sources and reservoirs have already been reported our results indicate that most biomarkers are not fractionated as the primary migration of petroleum within source rocks takes place the 20s 20s 20r ratio of c27 steranes is uniform in the whole source rock sequence while the 20s 20s 20r ratio of c29 steranes shows indistinctly high values in the reservoir unit the 20s 20s 20r ratio of diasteranes and the 22s 22s 22r ratio of c31 17 hopanes do not appear to have been fractionated which may be a result of the thermal isomerization reactions predominating over and masking out the possible fractionation effects diasteranes steranes ratios do not exhibit features that suggest an association with fractionation but rather are broadly correlated with lithology however compared to the diasteranes steranes ratios the ts ts tm ratio is much more sensitive to changes in mineral compositions variations in the ts ts tm ratio show a positive correlation r2 0 73 with mixed layer illite smectite content fractionation in the ts ts tm ratio if it has so occurred may be subsequently overprinted by in situ clay catalyzed reactions

chemometric differentiation of crude oil families in the san joaquin basin california chemometric analyses of geochemical data for 165 crude oil samples from the san joaquin basin identify genetically distinct oil families and their inferred source rocks and provide insight into migration pathways reservoir compartments and filling histories in the first part of the study 17 source related biomarker and stable carbon isotope ratios were evaluated using a chemometric decision tree cdt to identify families in the second part ascendant hierarchical clustering was applied to terpane mass chromatograms for the samples to compare with the cdt results the results from the two methods are remarkably similar despite differing data input and assumptions recognized source rocks for the oil families include the 1 eocene kreyenhagen formation 2 eocene tumey formation 3 4 upper and lower parts of the miocene monterey formation buttonwillow depocenter and 5 6 upper and lower parts of the miocene monterey formation tejon depocenter ascendant hierarchical clustering identifies 22 oil families in the basin as corroborated by independent data such as carbon isotope ratios sample location reservoir unit and thermal maturity maps from a three dimensional basin and petroleum system model five families originated from the eocene kreyenhagen formation source rock and three families came from the overlying eocene tumey formation fourteen families migrated from the upper and lower parts of the miocene monterey formation source rocks within the buttonwillow and tejon depocenters north and south of the bakersfield arch the eocene and miocene families show little cross stratigraphic migration because of seals within and between the source rocks the data do not exclude the possibility that some families described as originating from the monterey formation actually came from source rock in the temblor formation

geothermometry and geobarometry of overpressured lower paleozoic gas shales in the jiaoshiba field central china insight from fluid inclusions in fracture cements the wufeng longmaxi organic rich shales host the largest shale gas fields of china this study examines sealed fractures within core samples of the wufeng longmaxi shales in the jiaoshiba shale gas field in order to understand the development of overpressures in terms of magnitude timing and burial in wufeng longmaxi shales and thus the causes of present day overpressure in these paleozoic shale formations as well as in all gas shales quartz and calcite fracture cements from the wufeng longmaxi shale intervals in four wells at depth intervals between 2253 89 m and 3046 60 m were investigated and the fluid composition temperature and pressure during natural fracture cementation determined using an integrated approach consisting of petrography raman spectroscopy and microthermometry many crystals in fracture cements were found to contain methane inclusions only and aqueous two phase inclusions were consistently observed alongside methane inclusions in all cement samples indicating that fluid inclusions trapped during fracture cementation are saturated with a methane hydrocarbon fluid homogenization temperatures of methane saturated aqueous inclusions provide trends in trapping temperatures that th values concentrate in the range of 198 5 c 229 9 c 196 2 c 221 7 c for quartz and calcite respectively pore fluid pressures of 91 8 139 4 mpa for methane inclusions calculated using the raman shift of c h symmetric stretching v1 band of methane and equations of state for supercritical methane indicate fluid inclusions trapped at near lithostatic pressures high trapping temperature and overpressure conditions in fluid inclusions represent a state of temperature and overpressure of wufeng longmaxi shales at maximum burial and the early stage of the yanshanian uplift which can provide a key evidence for understanding the formation and evolution of overpressure our results demonstrate that the main cause of present day overpressure in shale gas deposits is actually the preservation of moderate high overpressure developed as a result of gas generation at maximum burial depths

gas isotope reversals in fractured gas reservoirs of the western canadian foothills mature shale gases in disguise isotopically reversed gases 13c methane 13c ethane 13c propane occur in fractured mixed clastic carbonate reservoirs of the permian and the triassic in the foothills at the western edge of the western canada sedimentary basin wcsb the 13c methane values 42 to 24 gas dryness and organic maturity ro 2 2 are indicative of mature gases and gas maturity generally increases with reservoir age and from the southeast to the northwest the 13c ethane values range from 44 to 25 with the less negative values in isotopically normal gases to the northeast of the gas fields we studied to explain the gas isotope reversals observed in the wcsb foothills we adopt the concept of a closed system shale in which simultaneous cooking of kerogen oil and gas yields gas with light 13c ethane and heavy 13c methane this gas was released from shales and trapped in fractured folds of brittle clastic carbonate rocks during deformation and thrust faulting of the laramide orogeny creating some of the most prolific gas pools these gases are actually mature shale gases local high abundances of h2s and co2 are most likely the products of thermochemical sulfate reduction tsr reactions in anhydrite rich interbeds and underbeds that admixed to the released shale gas during the tectonic event no evidence exists that tsr is responsible for the isotope reversals variations in 13c ethane are likely caused by local differences in thermal history the timing of gas release from shale and the timing of the fault and fold development less negative 13c ethane values resulting in isotopically normal gases to the northeast of the fields and in the underlying devonian carbonates likely reflect a more open shale system where the earliest generated gas was lost we suggest that isotopic reversals are restricted to closed system maturation and that their magnitude may be related to the relative volume of gas retained in shales

characterizing the shale gas resource potential of devonian mississippian strata in the western canada sedimentary basin application of an integrated formation evaluation devonian mississippian strata in the northwestern region of the western canada sedimentary basin wcsb were investigated for shale gas potential in the subsurface thermally mature strata of the besa river horn river muskwa and fort simpson formations attain thicknesses of more than 1 km 0 6 mi encompassing an area of approximately 125 000 km2 48 300 mi2 and represent an enormous potential gas resource total gas capacity estimates range between 60 and 600 bcf section of particular exploration interest are shales and mudrocks of the horn river formation including the laterally equivalent lower besa river mudrocks muskwa formation and upper besa river formation which yield total organic carbon toc contents of up to 5 7 wt fort simpson shales seldom have toc contents above 1 wt horn river and muskwa formations have excellent shale gas potential in a region between longitudes 122w and 123w and latitudes 59n and 60n national topographic system nts 94o08 to 94o15 in this area which covers an areal extent of 6250 km2 2404 mi2 average toc contents are higher 3 wt as determined by wire line log calibrations and have a stratal thickness of more than 200 m 656 ft gas capacities are estimated to be between 100 and 240 bcf section and possibly greater than 400 tcf gas in place a substantial percentage of the gas capacity is free gas caused by high reservoir temperatures and pressures muskwa shales have adsorbed gas capacities ranging between 0 3 and 0 5 cm3 g 9 6 16 scf t at reservoir temperatures of 60 80c 140 176f whereas besa river mudrocks and shales have low adsorbed gas capacities of less than 0 01 cm3 g 0 32 scf t liard basin region because reservoir temperatures exceed 130c 266f potential free gas capacities range from 1 2 to 9 5 cm3 g 38 4 to 304 scf t when total pore volumes 0 4 6 9 are saturated with gas the mineralogy has a major influence on total gas capacity carbonate rich samples indicative of adjacent carbonate platform and embayment successions commonly have lower organic carbon content and porosity and corresponding lower gas capacity 1 toc and 1 porosity seaward of the carbonate slave point edge muskwa and lower besa river mudrocks can be both silica and toc rich up to 92 quartz and 5 wt toc and most favorable for shale gas reservoir exploration because of possible fracture enhancement of the brittle organic and siliceous rich facies however an inverse relation between silica and porosity in some regions implies that zones with the best propensity for fracture completion may not provide optimal gas capacity and a balance between favorable reservoir characteristics needs to be sought

pore characteristic responses to categories of depositional microfacies of delta lacustrine tight reservoirs in the upper triassic yanchang formation ordos basin nw china abstract primary depositional variations interact with diagenetic modifications to exert strong control on pore networks in tight hydrocarbon reservoirs however the linkage between pore characteristics and depositional microfacies remains enigmatic which restricts the prediction of high quality reservoir distributions the continental tight reservoirs of the yanchang formation in the ordos basin are targeted to clarify and estimate the sensitivity of pore characteristics to depositional microfacies a multi methodical approach utilizing petrographic assessments logging evaluations digital imaging analyses and high pressure mercury intrusion experiments enables us to reveal the high microheterogeneity of pore types pore size distribution and pore fractal features the results identified the microfacies including distributary channels dcs mouth bars mbs interdistributary bays ibs sheet sands sss turbidite fans tfs shallow lacustrine mudstones slms and semi deep lacustrine mudstones sdlms from the chang 8 to chang 6 members dominated by residual intergranular pores and microfractures the main storage spaces of the dc and mb microfacies are within mesopores which provide 62 92 and 81 of the total pore volume respectively however the micropores that are mainly composed of clay intercrystalline pores and feldspar dissolved pores provide 55 70 52 62 and 53 80 of the total pore volume for the ib slm and sdlm microfacies respectively in addition the pore fractal dimension results indicate that the mesoporous structure of the argillaceous microfacies ib slm and sdlm is more heterogeneous than that of the arenaceous microfacies dc mb and tf therefore the dominant reservoir spaces of the different depositional microfacies are distributed over diverse pore radius ranges and the varying degrees of mesoporous development are a crucial factor affecting the reservoir capacity moreover the fractal dimensions have a significant negative correlation with pore volume in the meso micropore range characterized by lower pore sorting coefficients broader skewness and more abundant rigid siliceous grains the arenaceous microfacies with lower fractal dimensions and higher pore volume have better reservoir capacity than argillaceous microfacies that are rich in ductile minerals microscopic observations show that the muddier reservoirs of interdistributary bays and lacustrine mudstones are more susceptible to pore filling chlorite and illite which can deteriorate the reservoir quality these results indicate that the controlling effect of depositional microfacies on pore characteristics is fundamentally caused by differences in mineralogical composition and depositional texture and these results could provide new insights into the mechanisms of microfacies controls on reservoir quality

circum arctic petroleum systems identified using decision tree chemometrics source and age related biomarker and isotopic data were measured for more than 1000 crude oil samples from wells and seeps collected above approximately 55n latitude a unique multitiered chemometric multivariate statistical decision tree was created that allowed automated classification of 31 genetically distinct circum arctic oil families based on a training set of 622 oil samples the method which we call decision tree chemometrics uses principal components analysis and multiple tiers of k nearest neighbor and simca soft independent modeling of class analogy models to classify and assign confidence limits for newly acquired oil samples and source rock extracts geochemical data for each oil sample were also used to infer the age lithology organic matter input depositional environment and identity of its source rock these results demonstrate the value of large petroleum databases where all samples were analyzed using the same procedures and instrumentation

extracting phreatic evaporation from remotely sensed maps of evapotranspiration 1 one of the most important parameters related to soil salinization is the direct evaporation from the groundwater phreatic evaporation if the groundwater table is sufficiently close to the surface groundwater will evaporate through capillary rise in recent years several methods have been suggested to map evapotranspiration et on the basis of remote sensing images these maps represent the sum of both transpiration of vegetation and evaporation from the bare soil however identifying the amount of phreatic evaporation is important as it is the dominant flux in the salt balance of the soil the interpretation of stable isotope profiles at nonirrigated areas in the unsaturated zone allows one to quantify phreatic evaporation independently of the transpiration of the vegetation such measurements were carried out at different locations with a different depth to groundwater the benefit is twofold 1 a relation between phreatic evaporation rates and the depth to groundwater can be established 2 by subtracting the measured values of phreatic evaporation from remotely sensed values of et vadose et consisting of transpiration and excess irrigation water in the unsaturated zone can be estimated at the sampling locations a correlation between the normalized differential vegetation index and the calculated vadose et rates could be established r2 0 89 with this correlation the contribution of phreatic evaporation can be estimated this approach has been tested for the yanqi basin located in western china finally the distribution of phreatic evaporation was compared to a soil salinity map of the project area on a qualitative basis

relationship between reservoir diagenetic evolution and petroleum emplacement in the ula field north sea abstract the diagenetic and petroleum filling histories of the ula field have been studied by analysing aqueous and petroleum inclusions occurring in authigenic cements this study shows that diagenesis continues actively after the arrival of petroleum in the sandstones although the reaction rates and petroleum saturation remain obscure microthermometric measurements of fluid inclusions in authigenic quartz suggest an onset of extensive quartz cementation at temperatures around 110 c i e 2 5 km and that this cementation has continued to the present day synchronously with quartz cementation authigenic albite was formed as inter and intragranular cements large amounts of petroleum inclusions locally occur in the albite and quartz cements these inclusions were trapped in the cements as the main charge of petroleum arrived at the structure diffusion through thin water layers between the petroleum and the mineral surface would probably have dominated mass transfer of solutes for the precipitation of authigenic quartz and albite it is evident from analysis of the petroleum inclusions in early formed k feldspar overgrowths that some secondary migrated petroleum probably arrived in the reservoir at a shallow burial depth before the rapid subsidence in the last 25 my compared with petroleum in the free porosity of the ula formation the petroleum in the k feldspar inclusions is evidently sourced from a different source facies and most maturity parameters testify to the latter being less mature later trapped petroleum inclusions in quartz and albite have characteristics found both in k feldspar and in the ula formation dst oil and thus is likely to reflect the progressive change in the ula field petroleum charge which occurred during the time period of quartz diagenesis

textural and sequence stratigraphic controls on sealing capacity of lower and upper cretaceous shales denver basin colorado shale units can be important barriers to fluid flow in sedimentary basins and commonly serve as seals to petroleum reservoirs little is known however about the controls on shale permeability consequently variation in seal competency is one of the greatest risk factors associated with petroleum exploration here we examine possible controls on sealing capacity in two cretaceous marine shale units in the denver basin colorado sealing capacity as determined by mercury injection capillary pressure analysis is compared to several textural and compositional parameters and to sequence stratigraphic setting these two shale units display highly variable sealing capacity even between some adjacent samples this suggests that variability in some small scale shale characteristics may strongly influence sealing capacity the best seals are generally in transgressive systems tracts especially within or immediately below condensed sections textural characteristics of shale appear to be especially important in determining sealing capacity in particular well sorted pore throat sizes and well developed bedding parallel preferred orientation of flattened organic matter particles strongly favor high sealing capacity high degrees of bioturbation degrade sealing capacity possibly by disrupting preferred orientation and by increasing variability in grain size and hence in pore throat sorting preferred orientation of matrix clays parallel to bedding also appears to increase with increasing sealing capacity but is probably less important than the preferred orientation of organic matter compositional characteristics are generally less important than textural characteristics in determining sealing capacity in these shale units neither silt content nor cement content appears to be important to sealing capacity in these shale units total organic carbon is generally high in samples with good sealing capacity but can be either high or low where sealing capacity is poor overall the variables that most strongly favor high sealing capacity pore throat sorting organic matter bedding parallel preferred orientation and low bioturbation are most likely in anoxic deep water settings hence the association between good seals and condensed sections

primary migration by oil generation microfracturing in low permeability source rocks application to the austin chalk texas fracturing of low permeability source rocks is induced by pore pressure changes caused by the conversion of organic matter to less dense fluids oil and gas these fractures increase the permeability and provide pathways for hydrocarbon migration an equation for the pressure change is derived using four major assumptions 1 the permeability of the source rock is negligibly small 0 01 d 10 20 m2 so that the pore pressure buildup by the conversion is much faster than its dissipation by pore fluid flow 2 the stress state is isotropic so that horizontal and vertical stresses are equal the source rock fails when the pore pressure equals the overburden pressure 3 the properties of the rock organic matter and fluids remain constant during oil generation this assumption is valid when the change in depth i e pressure and temperature is small 4 only two reaction rates are required for the conversions a low temperature reaction rate for the kerogen oil conversion e approx 24 kcal mol a approx 1014 m y and a high temperature reaction rate for oil gas conversion e approx 52 kcal mol a approx 5 5 1026 m y the equations for generation rate and pressure change are applied to the austin source rock by adjusting the several variables to fit geochemical data core saturations and observed levels of oil and gas production this application demonstrates that the equations are easily applied in calculating depths of primary migration for low permeability source rocks

the impact of sediment provenance on barium based productivity estimates abstract biogenic barium in marine sediments has been suggested to be a reliable proxy of export productivity from the surface ocean and algorithms have been developed to link these properties however problems arise when the proposed algorithms are applied to predominantly terrigenous sediments a major source of error is incorrect estimates of the terrigenous ba al ratio in normative calculations of the amount of biogenic barium in the sediment compared to an often used global average ba al ratio much better results can be obtained by estimating the terrigenous ba al ratio from exponential regression of the ba al ratios of surface sediments obtained from continental slope transects this method has been applied to surface sediments from the chilean continental slope the calculated regional terrigenous ba al ratios could be verified with purely terrigenous samples from chilean rivers the resulting accumulation rates of biogenic barium on the chilean continental slope reliably reproduce the regional pattern of primary productivity in the southern peru chile current indicating the potential of biogenic barium as a useful paleo productivity proxy

cause of shale gas geochemical anomalies and mechanisms for gas enrichment and depletion in high maturity shales abstract this article reviews the abnormal characteristics of shale gases natural gases produced from organic rich shales and discusses the cause of the anomalies and mechanisms for gas enrichment and depletion in high maturity organic rich shales the reported shale gas geochemical anomalies include rollover of iso alkane normal alkane ratios rollover of ethane and propane isotopic compositions abnormally light ethane and propane 13 c values as well as isotope reversals among methane ethane and propane these anomalies reflect the complex histories of gas generation and associated isotopic fractionation as well as in situ mixing and accumulation of gases generated from different precursors at different thermal maturities a model was proposed to explain the observed geochemical anomalies gas generation from kerogen cracking at relatively low thermal maturity accounted for the increase of iso alkane normal alkane ratios and ethane and propane 13 c values normal trend simultaneous cracking of kerogen retained oil and wet gas and associated isotopic fractionation at higher maturity caused decreasing iso alkane normal alkane ratios lighter ethane and propane 13 c and corresponding conversion of carbon isotopic distribution patterns from normal through partial reversal to complete reversal relatively low oil expulsion efficiency at peak oil generation low expulsion efficiency at peak gas generation and little gas loss during post generation evolution are necessary for organic rich shales to display the observed geochemical anomalies high organic matter richness high thermal maturity high degrees of kerogen gas and oil gas conversions and late stage the stage of peak gas generation and post generation evolution closed system accounted for gas enrichment in shales loss of free gases during post generation evolution may result in gas depletion or even undersaturation total gas content lower than the gas sorption capacity in high maturity organic rich shales

ftir absorption indices for thermal maturity in comparison with vitrinite reflectance r0 in type ii kerogens from devonian black shales abstract ftir absorbance signals in kerogens and macerals were evaluated as indices for thermal maturity two sets of naturally matured type ii kerogens from the new albany shale illinois basin and the exshaw formation western canada sedimentary basin and kerogens from hydrous pyrolysis artificial maturation of the new albany shale were characterized by ftir good correlation was observed between the aromatic aliphatic absorption ratio and vitrinite reflectance r 0 ftir parameters are especially valuable for determining the degree of maturity of marine source rocks lacking vitrinite with increasing maturity ftir spectra express four trends i an increase in the absorption of aromatic bands ii a decrease in the absorption of aliphatic bands iii a loss of oxygenated groups carbonyl and carboxyl and iv an initial decrease in the ch 2 ch 3 ratio that is not apparent at higher maturity in naturally matured samples but is observed throughout increasing r 0 in artificially matured samples the difference in the ch 2 ch 3 ratio in samples from natural and artificial maturation at higher maturity indicates that short term artificial maturation at high temperatures is not fully equivalent to slow geologic maturation at lower temperatures with increasing r 0 the carboxyl carbonyl aromatic carbon ratio generally decreases except that kerogens from the exshaw formation and from hydrous pyrolysis experiments express an intermittent slight increase at medium maturity ftir derived aromaticities correlate well with r 0 although some uncertainty is due to the dependence of ftir parameters on the maceral composition of kerogen whereas r 0 is solely dependent on vitrinite

relative sea level cycles and organic matter accumulation in shales of the middle and upper devonian horn river group northeastern british columbia canada insights into sediment flux redox conditions and bioproductivity

calculated volume and pressure changes during the thermal cracking of oil to gas in reservoirs 1 the rising temperature that accompanies increasing burial depth converts oil in a reservoir into thermal gas a consideration of hydrogen balance during this cracking shows that approximately 3000 cubic ft 85 cubic meters of gas at standard temperature and pressure is generated from each barrel of oil in addition a graphitic residue is precipitated if the volume relationships among oil thermal gas and the graphitic residue are combined with data for gas solubility in pore water and gas nonideality z factor then pressure can be calculated for any degree of thermal cracking these calculations show that in an effectively isolated system pressures would become very high and could considerably exceed the rock load so that fracturing must occur causing pressure b eed off and loss of gas the lithostatic gradient 1 0 psi ft or 22 6 kpa m is reached after only about 1 0 of the oil is cracked if the reservoir system remains open i e at hydrostatic pressure and is initially filled with oil that is subsequently cracked to gas then roughly 75 of the gas will be lost or the reservoir volume must effectively increase in size for example by moving the gas water contact downward

methane cracking within shale rocks a new explanation for carbon isotope reversal of shale gas abstract shale gas with carbon isotope reversal 13cmethane 13cethane as a promising indicator for resource sweet spot tends to occur at high over maturity shales with high gas dryness index cmethane cmethane cethane 0 97 however the cause for this reversal is still controversial and remains an open question in the present work we propose methane cracking within high over matured shale rocks as one of the possible mechanisms to explain this reversal which will further enhance the knowledge about carbon isotope reversal of shale gas in order to validate this hypothesis methane pyrolysis experiments were carried out in closed gold tube system to investigate the mechanism of occurrence of carbon isotope reversal in shale gas from the pyrolysates the cracking of ch4 and the generation of higher number hydrocarbons like c2h4 c2h6 and c3h8 were detected the ch4 cracking and the subsequent formation of c2h6 led to the residual ch4 being enriched in 13c whereas the produced c2h6 is depleted in 13c based on our experimental results and the data analysis of 583 samples from shale gas reservoirs from different regions of the world we suggest that ch4 will be cracked and combined into c2h6 in high over matured shales when the contribution from methane derived c2h6 is sufficiently massive the commonly found order of 13cmethane 2 0 and a carbon isotope reversal will occur for the shale gas the barnett shale from fort worth basin usa as the application representative shale gas reservoir cover the evolution scope of the increase and subsequent decrease of 13cethane along with increase of 13cmethane and thus the beginning of the carbon isotope reversal

mississippian barnett shale fort worth basin north central texas gas shale play with multi trillion cubic foot potential the mississippian barnett shale serves as source seal and reservoir to a world class unconventional natural gas accumulation in the fort worth basin of north central texas the formation is a lithologically complex interval of low permeability that requires artificial stimulation to produce at present production is mainly confined to a limited portion of the northern basin where the barnett shale is relatively thick 300 ft 92 m organic rich presentday total organic carbon 3 0 thermally mature vitrinite reflectance 1 1 and enclosed by dense limestone units able to contain induced fractures the most actively drilled area is newark east field currently the largest gas field in texas newark east is 400 mi 2 1036 km 2 in extent with more than 2340 producing wells and about 2 7 tcf of booked gas reserves cumulative gas production from barnett shale wells through 2003 was about 0 8 tcf wells in newark east field typically produce from depths of 7500 ft 2285 m at rates ranging from 0 5 to more than 4 mmcf day estimated ultimate recoveries per well range from 0 75 to as high as 7 0 bcf efforts to extend the current barnett play beyond the field limits have encountered several challenges including westward and northward increases in oil saturation and the absence of lithologic barriers to induced fracture growth patterns of oil and gas occurrence in the barnett in conjunction with maturation and burial history data indicate a complex multiphased thermal evolution with episodic expulsion of hydrocarbons and secondary cracking of primary oils to gas

the oleaginous botryococcus from the triassic yanchang formation in ordos basin northwestern china morphology and its paleoenvironmental significance high abundance but rather low diversity algal fossils were found in the hydrocarbon source rocks of the ch 7 2 ch 7 3 section triassic yanchang formation in the xifeng area of southwest ordos basin which are mainly composed of prolific leiosphaeridia and botryococcus botryococcus colonies are of various forms the majority is nubbly with some of cluster and cotton shape the nubbly colonies appear globular cordiform ternate petal obtuse triangle chrysanthemum shape and so on most botryococcus are saffron or brown and are frequently covered with clay under transmission microscope and shows strong yellow and light brown under fluorescence microscope botryococcus could live in freshwater and brackish water the botryococcus colonies that lived in fresh water are small with small single cells arranged radially with undulant or indented edges the botryococcus colonies that lived in brackish water are bigger with larger single cells arranged irregularly with slippery contours the most of botryococcus are discovered from the organic rich argillaceous sediment with abundant pyrites in the semi and deep lake facies and shows they were preserved in low energy reducing environments taphonomic characteristics of various microfossils and the present of pediastrum in the phytoplankton flora indicate that they are in situ or near burial the lake area of the ordos basin was gradually expanding and reaching its most extensive flood surface in the ch 7 of yanchang formation interval during the middle and late triassic with warm climate plentiful rainfall and luxuriant vegetation as determined by the environmental analysis with botryococcus in xifeng area the presence of two ecological types of botryococcus indicates that the salinity of lake water was fluctuating in the ch 7 interval the occurrence of symbiotic acritarchs and geochemical salinity indices show that the ordos lake was a typical fresh water lake which was gradually desalted and its salinity fluctuation was narrow during the mid later triassic the ecological type of the palynological flora discovered from the ch 7 to ch 8 in xifeng area is similar to that from the fuxian lake with abundant botryococcus in the yungui plateau of china these findings imply that the ordos basin was in a lower latitude area of temperate to subtropical climate during the middle and late triassic

uncertainties around modelling of steady state phreatic evaporation with field soil profiles of δ18o and chloride summary the application of the general advection diffusion equation to model phreatic evaporation flux rates from solute concentration soil profiles has been applied to a variety of arid zone locations but the effects of heterogeneous and uncertain field data on modelling performance are rarely described we revisit and extend the model by accounting for the effects of variable water content and sediment type on the impedance factor and in turn effective diffusion coefficient we explore the local sensitivity of the extended model to its major assumptions and parameter values the mean diffusion coefficient of the soil profile data is most sensitive to the volumetric water content close to the evaporation front and so modelled evaporation results can be very sensitive to uncertainty around the position of the evaporation front the uncertainty in the position of the groundwater reservoir and its concentration has little effect where the lower part of the profile shows an asymptotic trend towards a representative value of groundwater concentration but can vary substantially with different values of groundwater depth and concentration if this is not the case field data from the southern margin of the great artesian basin are shown to exhibit considerable uncertainty around the boundary conditions of the advection diffusion model e g position of evaporation front depth and concentration of lower groundwater boundary condition resulting phreatic evaporation flux estimates show a wide range that needs to be considered when using these data in water balance studies of groundwater systems

geochemical significance of 17α h diahopane and its application in oil source correlation of yanchang formation in longdong area ordos basin china abstract relatively high abundance of 17 h c30 rearranged hopane has been detected in some oils and rock extracts from yanchang formation of longdong area southwestern ordos basin oil shale silty mudstone and carbonaceous mudstone extracts from yanchang formation all have low abundance of c30 rearranged hopane while high concentrations of c30 rearranged hopane were observed in the dark mudstone extracts analysis on the geochemical parameters of the organic matter origin thermal maturity and sedimentary organic facies were carried out the result showed that the depositional redox environment and lithology may be the critical factors for the rearrangement of hopanes which usually occurred in suboxic condition with clay catalyzed reactions as is consistent with the viewpoint of peters and moldowan 1993 according to the relative abundance of diahopane three oil classes can be identified class 1 oil with low abundance of diahopanes was originated from oil shale of chang 7 member while class 2 oil and class 3 oil with middle to high abundance of diahopanes were derived from dark mudstones of chang 4 5 to chang 9 members of yanchang formation of the 151 analyzed oil and extracts samples from different stratigraphic intervals 105 samples belong to class 1 oil coming from oil shale while 46 samples belong to class 2 and class 3 oil derived from mudstones so oil shale of chang 7 member is the main effective source rock of longdong area and dark mudstones of chang 4 5 to chang 9 member are also important source rocks

hydrocarbon generation as a mechanism for overpressuring in rocky mountain region overpressured reservoirs are present in the deeper parts of most basins in the rocky mountain region a variety of conditions can cause overpressuring however most high pressures in the region are caused by present day or recently active oil and gas generation or generation in the last few million years in low permeability rock successions that still contain organic matter capable of yielding thermally generated hydrocarbons rocks with above normal pressure range from devonian to tertiary and commonly are associated with low permeability tight reservoirs most of the overpressuring occurs in cretaceous and tertiary rocks overpressuring in rocks older than cretaceous is rare and where present only occurs in strata with very rich hydrocarbon source beds such as the d vonian mississippian bakken formation most organically lean pre cretaceous source beds are no longer capable of yielding enough hydrocarbons to maintain abnormal pressure nearly all overpressured reservoirs and source rocks have temperatures of approximately 200 f 93 c or higher in addition available data indicate that hydrocarbon related overpressuring does not generally occur if vitrinite reflectance ro values are less than 0 6 in oil prone strata or less than 0 7 in gas prone strata overpressured gas bearing strata generally have ro values of 0 8 or higher maximum reservoir pressures are about equal to the fracture gradient pressure in the reservoir rocks some vertical fractures in reservoir rocks are probably caused by rapid expulsion of hydrocarbons from the source beds high pressures in the rocky mountain region means that the rock succession is gas or oil saturated and discrete hydrocarbon water contacts are generally not present classical concepts of hydrodynamics do not appear to be applicable to these overpressured successions the optimum depths for exploration are generally the upper 1 000 2 000 ft 305 610 m of the overpressured succession

overpressure generation and evolution in lower paleozoic gas shales of the jiaoshiba region china implications for shale gas accumulation abstract overpressured shale gas plays have been found in the lower paleozoic marine shales of jiaoshiba region in the sichuan basin china the black shales from the upper ordovician wufeng group o3w and the lower part of lower silurian longmaxi group s1l are the producing reservoirs overpressure is widespread in the o3w s1l shales with the pressure coefficient up to 1 74 fluid inclusion microthermometric and raman spectroscopic techniques pvt and basin modeling are used to investigate overpressure generation and evolution in the o3w s1l shales the results show that thermocatalytic dry gas generation is the main genetic mechanism for overpressure development in the o3w s1l shales with specific characteristics as follows 1 the maximum burial depth of overpressured shales is more than 6200 m without anomalously low density and high primary porosity according to wireline log and core data 2 the over mature o3w s1l shales with the mean toc values ranging from 3 36 wt to 4 48 wt and the vitrinite reflectance values of 2 7 2 9 ro determined by kerogen ftir fourier transform infrared spectroscopy characteristics has excellent potential to produce dry gas 3 overpressured reservoirs are characterized by high gas saturations and the pressure coefficients positively correlate with gas saturation 4 the abnormally high pressures recorded in the fluid inclusions are coincident with high homogenization temperatures which is supportive of overpressure occurring during dry gas generation and provides convincing in situ evidence for gas generation overpressuring the calculated pore fluid pressures for methane inclusions within the maximum buried o3w s1l shales are approximately 90 3 139 4 mpa suggesting that gas generation produced a maximum pressure gradient of 23 1 mpa km which is equivalent to the lithostatic magnitudes the overpressure evolution in the o3w s1l shales is noticed to have evolved through four stages a rapidly increasing overpressure caused by thermocatalytic gas generation 145 85 ma a rapid pressure release 85 61ma overpressure preservation 61 20 ma and a relatively slow pressure release 20 ma present during post generation evolution 85 ma present of the o3w s1l shales both the overpressure and pressure coefficients decreased with time due to the intensive tectonic uplifts and denudation and approximately 19 0 28 5 of the initial total gas content was continuously released until the present day overpressure state the study of overpressure evolution in the o3w s1l shales provides basic information for the further study of the conversion between adsorbed gas and free gas and the method and technique used in this study to stress the overpressure generation and evolution may be generally applied to other overpressured or normally pressured shale gas systems

mechanisms of shale gas storage implications for shale gas exploration in china this article reviews the mechanisms of shale gas storage and discusses the major risks or uncertainties for shale gas exploration in china at a given temperature and pressure the gas sorption capacities of organic rich shales are primarily controlled by the organic matter richness but may be significantly influenced by the type and maturity of the organic matter mineral composition especially clay content moisture content pore volume and structure resulting in different ratios of gas sorption capacity gsc to total organic carbon content for different shales in laboratory experiments the gsc of organic rich shales increases with increasing pressure and decreases with increasing temperature under geologic conditions assuming hydrostatic pressure gradient and constant thermal gradient the gsc increases initially with depth due to the predominating effect of pressure passes through a maximum and then decreases because of the influence of increasing temperature at greater depth this pattern of variation is quite similar to that observed for coals and is of great significance for understanding the changes in gsc of organic rich shales over geologic time as a function of burial history at an elevated temperature and pressure and with the presence of moisture the gas sorption capacities of organic rich shales are quite low as a result adsorption alone cannot protect sufficient gas for high maturity organic rich shales to be commercial gas reservoirs two models are proposed to predict the variation of gsc and total gas content over geologic time as a function of burial history high contents of free gas in organic rich shales can be preserved in relatively closed systems loss of free gas during postgeneration uplift and erosion may result in undersaturation the total gas contents lower than the sorption capacity and is the major risk for gas exploration in marine organic rich shales in china

conceptual model for origin of abnormally pressured gas accumulations in low permeability reservoirs the largest gas fields in the rocky mountain region occur in abnormally pressured reservoirs these gas accumulations are different from more conventional gas accumulations in that they are commonly located in basin center positions they occur downdip from water bearing rocks and they are in overpressured or underpressured low permeability reservoirs we suggest that overpressured and underpressured gas accumulations of this type have a common origin in basins containing overpressured gas accumulations rates of thermogenic gas accumulation exceed gas loss causing fluid gas pressure to rise above the regional hydrostatic pressure within the overpressured gas generation zone free water in the larger pores is forced out of the gas generation zone into overlying and updip normally pressured water bearing rocks the remaining tightly bound water at irreducible saturation levels cannot remove dissolution products precluding significant permeability and porosity enhancement thus while other diagenetic processes continue a pore network with very low permeability develops as a result gas accumulates in these low permeability reservoirs at rates higher than it is lost in basins containing underpressured gas accumulations rates of gas generation and accumulation are less than gas loss these basins have typically experienced significant uplift and erosion and or temporal variations of paleotemperature despite these modifications the basin center gas accumulation persists but because of changes in the basin dynamics the overpressured accumulation evolves into an underpressured system

the impact of composition on pore throat size and permeability in high maturity shales middle and upper devonian horn river group northeastern british columbia canada abstract shale reservoirs of the middle and upper devonian horn river group provide an opportunity to study the influence of rock composition on permeability and pore throat size distribution in high maturity formations sedimentological geochemical and petrophysical analyses reveal relationships between rock composition pore throat size and matrix permeability in our sample set measured matrix permeability ranges between 1 69 and 42 81 nanodarcies and increases with increasing porosity total organic carbon toc content positively correlates to permeability and exerts a stronger control on permeability than inorganic composition a positive correlation between silica content and permeability and abundant interparticle pores between quartz crystals suggests that quartz may be another factor enhancing the permeability pore throat size distributions are strongly related to toc content in organic rich samples the dominant pore throat size is less than 10 nm whereas in organic lean samples pore throat size distribution is dominantly greater than 20 nm sem images suggest that in organic rich samples organic matter pores are the dominant pore type whereas in quartz rich samples the dominant type is interparticle pores between quartz grains in clay rich and carbonate rich samples the dominant pore type is intraparticle pores which are fewer and smaller in size high permeability shales are associated with specific depositional facies massive and pyritic mudstones rich in toc and quartz have comparatively high permeability laminated mudstone bioturbated mudstone and carbonate facies which are relatively enriched in clay or carbonate have fairly low permeability

division of fine grained rocks and selection of sweet sections in the oldest continental shale in china taking the coexisting combination of tight and shale oil in the permian junggar basin abstract the permian formation in the junggar basin contains the oldest continental shale in china and has abundant petroleum resources the lithofacies and lithology of the shale strata in the lucaogou formation which are characterized by two sets of coexisting combinations of tight oil and shale oil in the jimsar sag eastern junggar basin are studied via experiments to explore their petrophysics geochemistry reservoir pores and oil bearing properties the results show that 1 the lucaogou formation in the jimsar sag consists of shallow deep lacustrine sediments and can be divided into six stratigraphic units vertically 2 fine grained sediments in the sag composed of shale dolomite and siltstone can be specifically divided into carbonate mudstone cm siliceous mudstone sm carbonate rock cc carbonate sandstone cs and siliceous sandstone ss 3 cm and sm are good source rocks for shale oil and p 2 l 2 and p 2 l 5 are the sweet sections for shale oil cc cs and ss are reservoirs of tight oil and p 2 l 1 and p 2 l 4 are the sweet sections for tight oil finally definitions are discussed and proposed for tight oil and shale oil

geochemical paleoredox indicators in devonian mississippian black shales central appalachian basin usa the degree of anoxia that existed during accumulation of devonian mississippian black shales in central kentucky has been debated widely in this study geochemical data were used to elucidate paleodepositional environments for these units using analyses from ten cores collected from the outcrop belt in central kentucky sulfur carbon and selected trace element relationships were compared the sunbury shale tournasian lower mississippian and the cleveland and huron members of the ohio new albany shale fammenian upper devonian show different relationships between carbon sulfur and trace elements c s fe relationships for the sunbury suggest anoxic possibly even euxinic conditions prevailed during sediment accumulation analysis of c s fe data suggests that the cleveland may have accumulated under anoxic conditions with intermittent dysoxia whereas the huron member may have accumulated under a relatively wide range of conditions from anoxic to dysoxic to possibly oxic these three units exhibit different degrees of trace element enrichment with the approximate order of enrichment relative to an average shale being mo pb zn v ni cu cr co the sunbury shows the highest levels of enrichment followed by the cleveland with the huron showing only slight enrichment for most of these trace elements differing degrees of enrichment may reflect differences in depositional environment during accumulation high mo concentrations in the sunbury generally 200 550 ppm may infer euxinic conditions prevailed during sediment accumulation the cleveland and the huron both show considerably lower mo contents averaging around 100 ppm geochemical ratios including ni co v cr and v v ni also indicate variable paleoredox conditions for these shales based on previously established thresholds v cr and ni co ratios infer at least anoxic conditions during accumulation of the sunbury anoxic to dysoxic conditions during cleveland accumulation and dysoxic to oxic conditions for the huron v v ni ratios tend to indicate consistently lower oxygen regimes than do other paleoredox indicators and this discrepancy is greatest for the huron member it is suggested that thresholds established for paleoredox indicators in previous studies should not be applied strictly but that relative differences in these indicators collectively can infer variations in the degree of anoxia in addition relationships between corg and redox elements may help elucidate the role of anoxia in om accumulation it may be concluded from this study that the devonian mississippian black shales of central kentucky accumulated under variable bottom water conditions at least anoxic conditions prevailed during accumulation of much of the sunbury shale and the upper part of the cleveland member and possibly euxinic conditions for the sunbury bottom water conditions may have been intermittently anoxic and dysoxic during deposition of the lower cleveland during accumulation of the huron member it is likely that conditions ranged from anoxic to dysoxic to marginally oxic possibly being close to normal marine conditions at times during accumulation of the lowermost huron sediments

simple kinetic models of petroleum formation part iii modelling an open system abstract the movement of petroleum from organic rich source beds to potential carrier beds is the net result of two processes expulsion the release of generated petroleum from kerogen within the source bed and primary migration flow of a petroleum phase through the inorganic void networks of the source bed and all other intervening fine grained rocks expulsion is by far the more important process within the source bed orgas a simple zero dimensional model of the source rock as an open system explicitly models expulsion concurrent with oil and gas generation and oi lgas cracking as a storage threshold problem oil and gas are retained adsorbed absorbed within kerogen until their concentrations exceed the respective sorptive capacity of the residual organic carbon 0 1 and 0 02 g g ck 1 the initial hydrogen index hl 0 controls the important balance between potential sorbate petroleum and sorbant residual carbon using simple geochemical measurements the initial organic carbon is divided into initial oil inert kerogen and oil and gas generative reactive kerogen components reactive kerogens are assigned to one of five global kinetic organofacies with pre determined kinetic parameter sets governing separately rates of oil and gas generation kinetic parameters governing the rates of oil cracking within the source rock are predicted from hl 0 the two most important determinants of source rock behaviour are organofacies and hl 0 at a reference constant heating rate of 2 c ma 1 the projected oil expulsion threshold for typical organofacies members increases in the order a de 100 110 120 135 c f typically expels no oil an order of magnitude increase decrease in heating rate increases decreases these thresholds by ca 15 c typical cumulative gas mass fractions in their ultimate expulsion products are a f 0 25 0 3 0 25 0 65 and 1 0 g g 1 a value of 200 mg hc g c 1 is an approximate minimum hl 0 prerequisite for oil expulsion irrespective of absolute petroleum potential p 0 as a family coals vary dramatically in their expulsion behaviour as their hl 0 ranges both above and velow this value primary migration is efficient for expulsive source rocks movement within the source bed is limited only at low p 0 a source rocks total genetic potential p 0 thickness becomes important during migration outside the source bed it potentially restricts the primary migration distance and the excess of petroleum available for secondary migration and entrapment we evaluate primary migration approximately using a small migration loss factor no more than about 10 saturation of porosity or 1 mg g 1 coupled with an understanding of fluid potential gradients which determine migration direction within the stratigraphic architecture ultimately kerogen degradation and oil to gas cracking in the source rock are the rate limiting processes in petroleum accumulation

geochemistry characteristics and significance of two petroleum systems near top overpressured surface in central junggar basin nw china abstract most hydrocarbons discovered in the central junggar basin are endowed in limited areas below and above top overpressured surface by studying geochemical and distribution characteristics of hydrocarbons in reservoirs near top overpressured surface it was found that the lacustrine dark mudstone in middle lower permian and coal measures in jurassic are the major source rocks crude oils from these two sets of source rocks have apparently different geochemical indexes their maturity values are 0 7 1 0 higher in permian the natural gas is mainly coal derived wet gas from jurassic formation with general maturity of 0 9 1 0 hydrocarbons in tectonic units have different distribution features depending on sources crude oil above top overpressured surface in western well pen 1 sag is from both middle and lower permian while crude oil in overpressure compartment is mainly from middle permian and natural gas is from hybrid sources crude oil near top overpressured surface in western changji sag is mainly from middle permian including some oil from hybrid sources the natural gas is mainly coal derived wet gas hydrocarbons in northern dongdaohaizi sag and eastern changji sag are mainly coal derived oil and gas in overpressure compartment hydrocarbons in the central junggar basin underwent two stages of accumulation and experienced two large scale chargings at the later stage to summarize geochemical and distribution characteristics of hydrocarbons in reservoirs near top overpressured surface in the central junggar basin can provide reference for understanding hydrocarbon accumulation regularity and predicting favorable exploration targets near top overpressured surface in this region and similar high overpressure and hydrocarbon generation basins

geostatistic recognition of genetically distinct shale facies in upper triassic chang 7 section the ordos basin north china abstract the ordos basin in north china may be one of the nonmarine basins with highest hydrocarbon generation per volume of sedimentary fill it has great potential for unconventional oil and gas exploration especially shale oil when evaluating and predicting shale oil resources the difference between different regions and different layers of shale is very obvious so it cannot be calculated simply by average a geostatistic decision tree was constructed based on a training set of 22 parameters geochemistry petrology and sedimentology for 110 shale samples from the basin which can be used to implement genetic classification of subsequently collected shale samples three shale facies are identified by the decision tree the properties of each facies are different such as toc kerogen type and sulfur content genetic properties indicate formation conditions and provide base for the geostatistic assignments the differential distribution of shale facies in the basin reflects their origins from different formation mechanism elements ratios isotopes and biomarkers can be used to infer the sedimentary environment for each shale facies facies 1 mainly occurs in the upper chang 7 section and shows evidence of quartz rich source rock deposited under suboxic anoxic condition facies 3 occurs at the lower chang 7 section and shows evidence of clay rich and pyrite rich shale deposited under reducing dysoxic conditions with numerous higher plants input facies 1 and 2 constitutes the upper chang 7 with interactive thick layers facies 2 and 3 constitute the lower chang 7 with interactive thin layers petrology geochemistry and sedimentology of the shale facies suggest facies 1 represents the suboxic anoxic upper chang 7 proximal quartz rich shale which has lower toc and sulfur content than other facies the organic lamina is straight but rare kerogen is type i and dominated by sapropel the content of saturated hydrocarbon in chloroform asphalt a extract is the highest facies 2 has higher toc value sulfur content and soluble hydrocarbon content than facies 1 it was formed in unstable hydrodynamic environment under weak anoxic condition it is characterized by abundant laminas with various deformation structures and more alginite and vitrinite in kerogen anoxic lower chang 7 distal sulfur rich shale source rock make up organic rich facies 3 7 0 17 0 wt toc this facies received more higher plant input than the other facies well preserved algae shells are common in numerous and flat laminas the content of chloroform asphalt of facies 3 is higher than that of other facies but among which the saturated hydrocarbon content is the lowest the aromatic non hydrocarbon and asphalt are the highest suggesting the fluidity of hydrocarbon is the worst compared to others this facies was formed in the environment where temperature is relative lower water is relative deeper productivity and salinity are relative higher and the reducibility is relative stronger a deeper understanding of shale classification and distribution is important for the accurate resource evaluation and optimal exploration planning of shale oil

the application of fluid inclusions to migration of oil and diagenesis in petroleum reservoirs abstract fluid inclusions can be used to interpret thermal history and petroleum maturation and migration relative to burial history temperature pressure and composition data collected from fluid inclusions are used to determine the environment of diagenesis and the timing of cementation and migration cements in petroleum reservoirs contain both oil and aqueous fluid inclusions fluorescence spectroscopy is used to identify oil inclusions and to determine the maturity of entrapped oil the lifetime of fluorescence induced by a pulsed laser is related to the api gravity of entrapped oil interpretation of fluid inclusion data depends on knowing the origin of fluid inclusions and the probability that they survive in the burial environment those aspects of fluid inclusion study are investigated by synthesizing oil and aqueous inclusions in calcite crystals in laboratory experiments examples of how fluid inclusions are used to determine the physico chemical environments of diagenesis in petroleum reservoirs and the timing of cementation and migration are given for the wealden basin england the mishrif formation dubai the smackover formation gulf coast u s a and jurassic sandstones offshore norway in the wealden basin temperature data from fluid inclusions are used to determine that oil migration occurred in the cretaceous and that the reservoir rocks have been uplifted to varying degrees at a time after migration distribution of oil inclusions indicates that generation and migration of oil was principally in the western part of the basin the geochemistry of oil inclusions in calcite cements from the mishrif formation dubai are used to determine the type and maturity of entrapped oil temperature data from oil and water inclusions are used to relate reservoir diagenesis to burial history and the migration of oil in deep smackover reservoirs oil contains h 2 s the origin of the h 2 s is examined by study of fluid inclusions containing h 2 s in jurassic sandstones offshore norway fluid inclusion studies show that silica cementation is related to burial depth whereas a later calcite cementation originated from invasion of a hot fluid

geochemical study of crude oils from the xifeng oilfield of the ordos basin china abstract the xifeng oilfield is the largest newly discovered oilfield in the ordos basin in order to determine the possible source crude oils collected systematically from the oilfield and an adjacent oilfield have been examined isotopically and molecularly the predominance of long chain n alkanes high abundance of c29 sterane lower ratios of c25 c26 tricyclic terpane and c25 tricyclic terpane c24 tetracyclic terpane and high c24 tetracyclic terpane c24 tetracyclic terpane c26 tricyclic terpanes ratio in the studied oils suggest generation from a source with mixed terrigenous and algal bacterial organic matter the presence of diterpenoid hydrocarbon with abietane skeletons is characteristic of the main contribution of higher land plants to the oils the biomarker distributions in the oils show that they were formed under a weakly reducing freshwater environment molecular maturity parameters indicate that the crude oils are mature the oil source rock correlation and oil migration investigation suggest that the oils in the xifeng oilfield originated from the source rocks of the yanchang formation deposited in a shallow to deep freshwater lacustrine environment especially chang 7 source rocks the data from the distribution of pyrrolic nitrogen compounds indicate that the charging direction of the chang 8 crude oils is mainly from the zhuang 12 well northeast of the oilfield toward the southwest this direction of oil migration is consistent with that indicated by regional geological data

pore characterization and methane sorption capacity of over mature organic rich wufeng and longmaxi shales in the southeast sichuan basin china abstract 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 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

exhumation charge the last gasp of a petroleum source rock and implications for unconventional shale resources petroleum oil and gas forms from the bacterial or thermal breakdown of kerogen during progressive burial in sedimentary basins during times of petroleum generation kerogens in organic rich source rocks expel petroleum to form a fluid phase in the pore system capable of migrating under hydrodynamic and buoyancy forces to ultimately escape to the surface or accumulate within petroleum traps in the subsurface the relative timing of petroleum charge and trap formation is a vital component in the accumulation of petroleum deposits exhumed basins have been historically viewed as higher risk targets for conventional petroleum exploration because of inter alia the switch off of petroleum generation in the source rock at the commencement of cooling during exhumation however even at the switch off point the source rock may retain a significant volume of petroleum sorbed in kerogen and within its pore system herein we demonstrate that if the source rock is exhumed to shallower depths after peak burial pore pressure reduction and the associated volumetric expansion of the petroleum particularly of the gaseous phase in the pore system will result in the discharge of additional petroleum into the adjacent carrier bed or reservoir formations because most onshore sedimentary basins are characterized by major exhumation events at some point in their history this represents an additional and underappreciated mechanism for a late stage petroleum charge in exhumed sedimentary basins the modeling also indicates that both the initial pre exhumation total gas storage capacity and the exhumation gas charge are likely to be volumetrically more significant for gas bearing source rocks that have been exposed to higher initial pressures and lower thermal gradients the concepts presented here also have implications for petroleum resources retained within unconventional shale reservoirs because high graded shale plays may be associated with systems where the magnitude or rate of relative overpressure dissipation has limited exhumation charge from the unconventional to conventional reservoirs within the basin

effects of early petroleum charge and overpressure on reservoir porosity preservation in the giant kela 2 gas field kuqa depression tarim basin northwest china kela 2 is a giant gas field with a proven reserve of 597 tcf in the kuqa depression northern tarim basin widespread overpressures have been encountered in the eocene and cretaceous sandstone reservoirs of the field with pressure coefficients up to 2 1 from drill stem tests and well log data analysis disequilibrium compaction associated with horizontal tectonic compression may be the dominant overpressure mechanism in the sandstone reservoirs because the overpressured sandstone with a maximum burial depth over 6000 m 19 685 ft displays anomalously high porosity and low density the causes for sandstone reservoirs with anomalously high porosity in the kela 2 gas field were studied based on an integrated investigation of sandstone reservoir characteristics paleo oil water contact petroleum charge history and overpressure evolution collective evidence indicates that early oil charge had retarded the porosity reduction of the reservoir sandstone and resulted in disequilibrium compaction from overburden rocks and overpressure from disequilibrium compaction and horizontal tectonic compression at the beginning of the rapid subsidence and deposition in the kela 2 gas field again contributed to the preservation of the reservoir porosity 1 overpressured mudstones in the kela 2 gas field are characteristic of normal compaction and overpressure was generated by horizontal tectonic compression instead of disequilibrium compaction 2 the reservoir sandstones with high porosity and permeability are associated with high paleo oil saturation as indicated by quantitative grain fluorescence qgf responses and anomalous qgf on extract intensity 3 sandstone units below the paleo oil water contact have very low porosity and permeability and 4 three episodes of oil and one episode of gas charge are identified in the sandstone reservoirs of the kela 2 gas field and the later two episodes of oil charge occurred circa 5 5 4 5 ma which corresponds to the beginning of the rapid tectonic subsidence and deposition in the kuqa depression the initially charged oil in the sandstone reservoirs was subsequently displaced by gas at circa 3 2 ma through fault activation at the edge of the anticline trap the overpressure evolution for the k1bs reservoir sandstone in the kela 2 gas field indicates that the apparent overpressure development in the sandstone reservoir began at 5 ma following the major oil charge and has been maintained to the present overpressure development from 5 ma in the sandstone reservoirs of the kela 2 gas field is believed to be the dominant cause of the porosity preservation

late quaternary right lateral displacement along active faults in the yanqi basin southeastern tian shan northwest china abstract late quaternary right lateral displacement and slip rates have been determined along wnw ese trending active faults in the intermontane yanqi basin on the southeastern flank of the chinese tian shan detailed analyses of satellite images and field investigation have revealed that the active kaidu river fault zone on the southern margin of the basin is a strike slip fault zone drainage systems incising late pleistocene holocene alluvial fans record between 3 and 250 m dextral offsets and show progressive displacement along the fault zone fault scarps developed in the alluvial fans range in height from 1 to 25 m and alternate along the strike of the fault zone from northeast to southwest facing in a left stepping en echelon pattern based on the offset of stream channels 14c dates of alluvial deposits and fabrics within fault rocks we infer that 1 the average right lateral slip rate is about 8 mm year with a vertical component of 1 mm year 2 the offset produced by individual seismic faulting event is typically 3 7 m 3 the average recurrence interval of large seismic events m 7 is ca 500 years and 4 the most recent movement occurred during the past 2 5 ky in the kaidu river fault zone these strike slip faults represent partitioning of horizontal slip within an otherwise thrust dominated orogen related to the india eurasia collision within the tian shan during late quaternary