3 d imaging of marlborough new zealand subducted plate and strike slip fault systems summary we present a 3 d seismic velocity model of the northern south island new zealand using several combined passive and active source data sets this area is the transition from hikurangi subduction in the north island to oblique continental collision along the alpine fault and the southern alps and geodetically observed deformation is consistent with plate motion being primarily taken up on a series of rotating strike slip faults we carry out simultaneous inversion for vp and vp vs and hypocentres using earthquake data recorded by the permanent seismic network and three temporary seismic arrays also using active source marine airgun data recorded at onshore stations we image the subducted hikurangi slab as a continuous unbroken feature extending from the active subduction zone to the north beneath the marlborough region the 3 d hypocentres define the subducted slab as a smooth curved feature to over 250 km depth whereas below the junction of the awatere and alpine faults the seismicity abruptly ends at 100 km depth the subducting pacific plate has a thick crust including greywacke upper crust which slows subduction the interaction of the subducted plate with the translating overlying plate forms a 50 km long zone of apparent crustal thickening with vp 7 0 km s 1 observed to 40 km depth the australian plate has a high velocity block to 65 km depth aligned with the separation point pluton and trending oblique to the subducted slab this zone of thicker australian lithosphere may also hinder subduction the marlborough faults trend about 25 to the strike of the underlying subducted slab so that the relation of faults to the slab varies along the fault strikes and the overlying plate ranges in thickness from 20 to 50 km along the faults thus the fault interaction with the subducted slab varies from translating material directly above the subducting plate to bottoming into a thick ductile region the lower crust has high vp vs under the marlborough faults except for a region of haast schist which may indicate excess fluid released by the subducted plate

charging of the neogene penglai 19 3 field bohai bay basin china oil accumulation in a young trap in an active fault zone the penglai 19 3 pl19 3 oil field the largest offshore oil field in china was found in shallow reservoirs 700 1700 m 2297 5577 ft within the most active fault zone in east china the pl19 3 anticline was not finally formed until about 2 0 ma and is cut by densely distributed faults source rock and crude oil samples from the pl19 3 field were analyzed to determine the origin and formation mechanisms of this large oil field three organic rich oil prone source rock intervals exist in the bozhong subbasin each of which has a distinct biomarker assemblage oil samples from different wells have different biomarker associations and three source related oil classes were identified within the pl19 3 field based on biomarker compositions and multivariate analysis of the data the pl19 3 field displays considerable compositional heterogeneity the compositional heterogeneity within the field and comparison between oil samples from the pl19 3 field and those from nearby structures suggest three field filling directions which is consistent with the results of migration pathway modeling the pl19 3 field was charged in the north by oil generated from dongying formation source rocks in the eastern bozhong depression and bodong depression in the southeast by oil generated from shahejie formation source rocks in the miaoxi depression and in the northwest by oil generated from shahejie formation source rocks in the central bozhong depression oil charge from multiple source rock intervals and multiple generative kitchens and focusing of oil originating from a large area of the bozhong depression into the same trap resulted in rapid oil accumulation in the pl19 3 structure and the formation of this large oil field in a very young trap within an active fault zone

geologic framework of the mississippian barnett shale barnett paleozoic total petroleum system bend arch fort worth basin texas this article describes the primary geologic characteristics and criteria of the barnett shale and barnett paleozoic total petroleum system tps of the fort worth basin used to define two geographic areas of the barnett shale for petroleum resource assessment from these two areas referred to as assessment units the u s geological survey estimated a mean volume of about 26 tcf of undiscovered technically recoverable hydrocarbon gas in the barnett shale the mississippian barnett shale is the primary source rock for oil and gas produced from paleozoic reservoir rocks in the bend arch fort worth basin area and is also one of the most significant gas producing formations in texas subsurface mapping from well logs and commercial databases and petroleum geochemistry demonstrate that the barnett shale is organic rich and thermally mature for hydrocarbon generation over most of the bend arch fort worth basin area in the northeastern and structurally deepest part of the fort worth basin adjacent to the muenster arch the formation is more than 1000 ft 305 m thick and interbedded with thick limestone units westward it thins rapidly over the mississippian chappel shelf to only a few tens of feet the barnett paleozoic tps is identified where thermally mature barnett shale has generated large volumes of hydrocarbons and is 1 contained within the barnett shale unconventional continuous accumulation and 2 expelled and distributed among numerous conventional clastic and carbonate rock reservoirs of paleozoic age vitrinite reflectance ro measurements show little correlation with present day burial depth contours of equal ro values measured from barnett shale and typing of produced hydrocarbons indicate significant uplift and erosion furthermore the thermal history of the formation was enhanced by hydrothermal events along the ouachita thrust front and mineral wells newark east fault system stratigraphy and thermal maturity define two gas producing assessment units for the barnett shale 1 a greater newark east fracture barrier continuous barnett shale gas assessment unit encompassing an area of optimal gas production where dense impermeable limestones enclose thick 300 ft 91 m barnett shale that is within the gas generation window ro 1 1 and 2 an extended continuous barnett shale gas assessment unit covering an area where the barnett shale is within the gas generation window but is less than 300 ft 91 m thick and either one or both of the overlying and underlying limestone barriers are absent

application of organic facies studies to sedimentary basin analysis a case study from the yitong graben china abstract an organic facies is defined in this paper as a mappable stratigraphic unit containing organic matter om of a particular genetic type in certain abundance several concepts concerning organic facies are proposed and their significance in basin analysis is discussed in detail a combined sedimentological and organic geochemical investigation has been carried out in the yitong graben and four organic facies and one organic parafacies have been recognized distinct organic basin fill sequences obfs and organic facies association ofa were developed in different sub units of this graben which indicates that the yitong graben had undergone two tectonic subsidence cycles such tectonic subsidence patterns could not have been found out without detailed organic facies analysis confirming that organic facies especially obfs and ofa study is a very useful tool not only for prediction and three dimensional mapping of petroleum source rocks but also for sedimentary basin analysis

evolution of methane sorption capacity of coal seams as a function of burial history a case study from the campine basin ne belgium based on extensive data sets of high pressure sorption isotherms and canister desorption data from two central european coal basins campine and ruhr basins a computational scheme has been developed to calculate the maximum coal bed methane cbm sorption capacity of coal seams as a function of pressure temperature and coal rank in addition the effects of in situ moisture content and maceral composition have been tentatively implemented using this algorithm it is possible to explicitly take into account variations in sorption capacity of the coal seams in sedimentary basins over geologic time as a function of burial history and thermal evolution the procedure has been applied to model the evolution and the present day coal bed methane content of the campine basin ne belgium it is demonstrated how the present day gas content of the campine basin is controlled by the burial history of the coal layers throughout geologic time the maximum gas sorption capacity typically occurs at a depth range between 500 and 1000 m during periods of uplift and erosion 250 and 90 ma before present the uppermost coal layers have lost methane due to a reduction of gas storage capacity while their storage capacity has increased during periods of burial 300 and 180 ma ago and present additionally the present day gas content is controlled by the gas generation history coal layers which have lost storage capacity during geologic time will stay undersaturated if not replenished by late stage e g microbial gas the gas content profile of test well kb206 in the ne campine basin established from canister desorption tests can be reproduced by assuming that undersaturation of the coals is due to erosion and re burial and that no significant gas generation e g microbial gas has taken place after the time of maximal burial isotopic data d 178 13c 59 indicate the presence of a small portion of microbial gas the absolute gas contents in this well are lower than the calculated maximum present day sorption capacity this may be due to an underestimation of the effect of water content on sorption capacity or result from degassing via nearby faults enforced by fluid circulation

the importance of shale composition and pore structure upon gas storage potential of shale gas reservoirs abstract the effect of shale composition and fabric upon pore structure and ch 4 sorption is investigated for potential shale gas reservoirs in the western canadian sedimentary basin wcsb devonian mississippian d m and jurassic shales have complex heterogeneous pore volume distributions as identified by low pressure co 2 and n 2 sorption and high pressure hg porosimetry thermally mature d m shales 1 6 2 5 vro have dubinin radushkevich d r co 2 micropore volumes ranging between 0 3 and 1 2 cc 100 g and n 2 bet surface areas of 5 31 m 2 g jurassic shales which are invariably of lower thermal maturity ranging from 0 9 to 1 3 vro than d m shales have smaller d r co 2 micropore volumes and n 2 bet surface areas typically in the range of 0 23 0 63 cc 100 g co 2 and 1 9 m 2 g n 2 high pressure ch 4 isotherms on dried and moisture equilibrated shales show a general increase of gas sorption with total organic carbon toc content methane sorption in d m shales increases with increasing toc and micropore volume indicating that microporosity associated with the organic fraction is a primary control upon ch 4 sorption sorption capacities for jurassic shales however can be in part unrelated to micropore volume the large sorbed gas capacities of organic rich jurassic shales independent of surface area imply a portion of ch 4 is stored by solution in matrix bituminite solute ch 4 is not an important contributor to gas storage in d m shales structural transformation of d m organic matter has occurred during thermal diagenesis creating and or opening up microporosity onto which gas can sorb as such d m shales sorb more ch 4 per weight percent wt toc than jurassic shales inorganic material influences modal pore size total porosity and sorption characteristics of shales clay minerals are capable of sorbing gas to their internal structure the amount of which is dependent on clay type illite and montmorillonite have co 2 micropore volumes of 0 78 and 0 79 cc 100 g n 2 bet surface areas of 25 and 30 m 2 g and sorb 2 9 and 2 1 cc g of ch 4 respectively dry basis a reflection of microporosity between irregular surfaces of clay platelets and possibly related to the size of the clay crystals themselves mercury porosimetry analyses show that total porosities are larger in clay rich shales compared to silica rich shales due to open porosity associated with the aluminosilicate fraction clay rich sediments low si al ratios have unimodal pore size distributions

multiscale connectivity characterization of marine shales in southern china by fluid intrusion small angle neutron scattering sans and fib sem abstract an evaluation of shale pore connectivity is essential for predicting the production behavior and optimizing the development plan of shale gas to systematically investigate the multiscale connectivity characteristics and controlling factors complementary tests were conducted on four overmature marine shale samples from southern china one each from longmaxi formation and wufeng formation and two from niutitang formation with different maturity and composition the methods included mercury intrusion capillary pressure micp spontaneous imbibition with deionized water and n decane saturated diffusion distribution with seven nano sized tracers n2 physisorption small angle neutron scattering sans and focused ion beam scanning electron microscopy fib sem tomography moreover a novel repeated micp measurement technique was developed and used to evaluate the pore connectivity from the distribution behavior of residual mercury results indicate that the connectivity loss of hydrophilic pore networks owing to an increased maturity and the compaction causes pore shrinkage and bond breakage between pore networks according to the three dimensional reconstruction and pore network extraction of fib sem images pores in organic matter om have a good pore connectivity but the minerals surrounding the om reduce the overall pore connectivity of the shale matrix by evaluating the pore connectivity using different methods the hydrocarbon migration pattern in overmature marine shales was established our results imply that in addition to creating induced fracture networks effectively connecting induced fractures with preexisting microcracks or joint sets between om pore networks and transport pores can also be used to enhance overall pore connectivity microwave heating in shale reservoirs may be an effective way of further improving the production and recovery of hydrocarbons

geochemical constraints on the origin and volume of gas in the new albany shale devonian mississippian eastern illinois basin this study involved analyses of kerogen petrography gas desorption geochemistry microporosity and mesoporosity of the new albany shale devonian mississippian in the eastern part of the illinois basin specifically detailed core analysis from two locations one in owen county indiana and one in pike county indiana has been conducted the gas content in the locations studied was primarily dependent on total organic carbon content and the micropore volume of the shales gas origin was assessed using stable isotope geochemistry measured and modeled vitrinite reflectance values were compared depth of burial and formation water salinity dictated different dominant origins of the gas in place in the two locations studied in detail the shallower owen county location 415 433 m 1362 1421 ft deep contained significant additions of microbial methane whereas the pike county location 832 860 m 2730 2822 ft deep was characterized exclusively by thermogenic gas despite differences in the gas origin the total gas in both locations was similar reaching up to 2 1 cm3 g 66 scf ton lower thermogenic gas content in the shallower location lower maturity and higher loss of gas related to uplift and leakage via relaxed fractures was compensated for by the additional generation of microbial methane which was stimulated by an influx of glacial melt water inducing brine dilution and microbial inoculation the characteristics of the shale of the maquoketa group ordovician in the pike county location are briefly discussed to provide a comparison to the new albany shale

joint sets that enhance production from middle and upper devonian gas shales of the appalachian basin the marine middle and upper devonian section of the appalachian basin includes several black shale units that carry two regional joint sets j1 and j2 sets as observed in outcrop core and borehole images these joints formed close to or at peak burial depth as natural hydraulic fractures induced by abnormal fluid pressures generated during thermal maturation of organic matter when present together earlier j1 joints are crosscut by later j2 joints in outcrops of black shale on the foreland northwest side of the appalachian basin the east northeast trending j1 set is more closely spaced than the northwest striking j2 set however j2 joints are far more pervasive throughout the exposed devonian marine clastic section on both sides of the basin by geological coincidence the j1 set is nearly parallel the maximum compressive normal stress of the contemporary tectonic stress field shmax because the contemporary tectonic stress field favors the propagation of hydraulic fracture completions to the east northeast fracture stimulation from vertical wells intersects and drains j2 joints horizontal drilling and subsequent stimulation benefit from both joint sets by drilling in the north northwest south southeast directions horizontal wells cross and drain j1 joints whenever present then staged hydraulic fracture stimulations if necessary run east northeast i e parallel to the j1 set under the influence of the contemporary tectonic stress field thereby crosscutting and draining j2 joints

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

the global oil system the relationship between oil generation loss half life and the world crude oil resource discussion the global oil system is dynamic with fundamental parameters of volume time and flux rate with certain geological assumptions these parameters are mathematically linked by the equation half life 0 693 x volume filling rate reservoired conventional oil has a well defined half life of 29 m y derived from the distribution of oil generation ages the global oil reserve is therefore directly related to the global filling rate of reservoirs if the global system is in equilibrium then the reservoir filling rate cannot be less than the rate at which reservoirs seep i e leak to surface both filling and leaking parameters are poorly constrained total global oil generation is estimated to be about 2 7 million bbl yr surface seepage data suggest that at least 0 8 million bbl yr of this enters reservoirs the remainder escaping directly to surface without being trapped this seepage rate cannot be supported under equilibrium conditions by global oil reserves of the size commonly supposed the seepage rate implies global crude oil reserves of at least 4 trillion bbl whereas typical current estimates based upon geological analogs are 2 trillion bbl excluding tar sands either 1 the global oil system is out of equilibr um and reservoirs are draining faster than they fill or 2 seepage rates are lower than supposed or 3 most seepage is due to active generation and migration straight to surface rather than leaking reservoirs or 4 ultimate recoverable reserves are much greater than previously thought

characteristics and origins of coal cleat a review abstract cleats are natural opening mode fractures in coal beds they account for most of the permeability and much of the porosity of coalbed gas reservoirs and can have a significant effect on the success of engineering procedures such as cavity stimulations because permeability and stimulation success are commonly limiting factors in gas well performance knowledge of cleat characteristics and origins is essential for successful exploration and production although the coal cleat literature spans at least 160 years mining issues have been the principal focus and quantitative data are almost exclusively limited to orientation and spacing information few data are available on apertures heights lengths connectivity and the relation of cleat formation to diagenesis characteristics that are critical to permeability moreover recent studies of cleat orientation patterns and fracture style suggest that new investigations of even these well studied parameters can yield insight into coal permeability more effective predictions of cleat patterns will come from advances in understanding cleat origins although cleat formation has been speculatively attributed to diagenetic and or tectonic processes a viable mechanical process for creating cleats has yet to be demonstrated progress in this area may come from recent developments in fracture mechanics and in coal geochemistry

chemostratigraphy of the posidonia black shale sw germany i influence of sea level variation on organic facies evolution abstract during the toarcian widespread deposition of organic rich mudrocks black shales occurred across europe linked to a 3rd order sea level rise we provide a high resolution multi proxy chemostratigraphic study of the dotternhausen sections in sw germany embedded in a stratigraphic and palecological framework chemostratigraphy and paleoenvironmental reconstruction is based on rock eval and elemental analysis of bulk organic matter and biomarker analysis of aliphatic hydrocarbon fractions aliphatic biomarker ratios applied to reconstruct the facies development include pristane phytane and pristane phytane n c 17 n c 18 ratios carbon preference index c 27 c 29 sterane and hopane sterane distribution results show that sea level change exerted the major control on the composition of primary produced organic matter and on its redox controlled preservation changes in primary production and in the ratio of terrestrially versus marine derived organic matter take place drastically at the onset of black shale deposition the relative proportion of terrestrial versus marine biomass accumulation is independently assessed by highly correlative bulk organic matter properties hi values and biomarker ratios cpi the terrestrially derived end member yields hi values of 50 100 mg hc toc and cpi values of 1 4 2 0 whereas the marine end member has hi values of 600 700 mg hc toc and cpi values of 0 95 1 05 correspondingly the shift in plant versus bacteria derived biomass is discriminated by hi values and hopane sterane ratios data were grouped according to their position in the lowstand lst lower and upper transgressive tst highstand systems tract hst and maximum flooding surface mfz of the sequence stratigraphic framework occurrence of organic matter with a significant bacterial contribution is restricted to the lst and lowermost tst and shows hopane sterane ratios of 0 25 0 5 marine phytoplanktonic matter dominates the upper tst hst and mfz with organic matter giving hopane sterane ratios between 0 5 and 1 7 samples from the hst yield hi values between 450 and 500 mg hc toc which is consistently lower by 150 mg hc toc when compared to the tst the lower quality of the organic matter deposited in the hst is due to its longer settling times through a thicker oxygenated water column a strong correlation with relative sea level stand and the c 27 c 29 sterane ratio is observed lst exhibits c 27 c 29 sterane ratios of 0 7 during transgression values increase to 1 0 reaching a maximum at 1 4 during sea level highstand thus reflecting decreasing terrigenous input and shifts in near shore versus open marine algal communities episodic fluctuation of anoxia is discussed on the basis of a monsoonal climate model which infers significant surface run off during summer monsoon providing high nutrient supply and associated high primary productivity in combination with a density stratified water column excellent preservation conditions for organic matter were established dry winter conditions with inversion of the surface water flow regime led to seasonal export of bottom waters and episodic establishment of dysoxic conditions variations in the extent of annual flushing of sub basins on the toarcian shelf controlled long term organic matter accumulation rate paleoclimate variability and its connection with sea level stand is thus of paramount importance for different modes of organic matter accumulation and redox system stability

impact of laminae on pore structures of lacustrine shales in the southern songliao basin ne china abstract evaluating the influences of laminae on shale pore structures is vital to understand the enrichment mechanism of lacustrine shale gas this study investigates lacustrine shales from the lower cretaceous shahezi formation in the changling sag southern songliao basin ne china using mineralogical and geochemical analyses co2 n2 adsorption and high pressure mercury intrusion porosimetry mip to compare pore structure characteristics between laminated and massive shales and elucidate their main controlling factors our results show that laminae in lacustrine shales from the shahezi formation include those clay rich organic rich and silty ones and minor carbonate rich ones micropores in both laminated and massive shales show tri modal distributions with main peaks at 0 47 0 54 nm 0 57 0 63 nm and 0 80 0 85 nm respectively however the laminated shales exhibit great variations in micropore volumes among different samples mesopores within the laminated shales are smaller than those in the massive shales and their pore volumes pv are about 1 3 less than those of the massive shales this is due to that the laminated shales are rich in slit like pores whereas the massive shales have more plate like and ink bottle pores thermal maturity ro and total organic carbon toc contents are the essential factors controlling the development of micropores and mesopores in the laminated shales however they show weak effects on macropore development in this formation this may be related to that shales from the shahezi formation generally have low toc contents and type iii kerogen clay minerals and quartz both have weak relevance to pore development in this formation

shale gas play risk of the lower cambrian on the yangtze platform south china this paper describes the establishment of shale gas play risk workflow and discusses the major geologic risks for the lower cambrian shale gas play on the yangtze platform the shale gas play risk is assessed by considering the probability of occurrence po of hydrocarbon charge reservoir and retention hcrr of a shale gas play the po of each of these three factors is determined according to geological understanding and data availability the risk of these factors is categorized into high risk po 0 3 relatively high risk 0 3 3 5 and poor hydrocarbon retention are the key geologic risks of the lower cambrian shale gas play uncertainty is inherent in the play risk assessment owing to sparse well data coverage understanding the play risks and uncertainties warrants further study of the impact of extremely high thermal maturities and burial history and how it facilitates decision making for exploration investment

unconventional shale gas systems the mississippian barnett shale of north central texas as one model for thermogenic shale gas assessment shale gas resource plays can be distinguished by gas type and system characteristics the newark east gas field located in the fort worth basin texas is defined by thermogenic gas production from low porosity and low permeability barnett shale the barnett shale gas system a self contained source reservoir system has generated large amounts of gas in the key productive areas because of various characteristics and processes including 1 excellent original organic richness and generation potential 2 primary and secondary cracking of kerogen and retained oil respectively 3 retention of oil for cracking to gas by adsorption 4 porosity resulting from organic matter decomposition and 5 brittle mineralogical composition the calculated total gas in place gip based on estimated ultimate recovery that is based on production profiles and operator estimates is about 204 bcf section 5 78 10 9 m 3 1 73 10 4 m 3 we estimate that the barnett shale has a total generation potential of about 609 bbl of oil equivalent ac ft or the equivalent of 3657 mcf ac ft 84 0 m 3 m 3 assuming a thickness of 350 ft 107 m and only sufficient hydrogen for partial cracking of retained oil to gas a total generation potential of 820 bcf section is estimated of this potential approximately 60 was expelled and the balance was retained for secondary cracking of oil to gas if sufficient thermal maturity was reached gas storage capacity of the barnett shale at typical reservoir pressure volume and temperature conditions and 6 porosity shows a maximum storage capacity of 540 mcf ac ft or 159 scf ton

petroleum migration and accumulation in the bozhong sub basin bohai bay basin china significance of preferential petroleum migration pathways ppmp for the formation of large oilfields in lacustrine fault basins abstract this paper discusses migration styles and primary controls of petroleum migration pathways in heterogeneous carrier beds in bozhong sub basin bohai bay basin modeling of secondary petroleum migration pathways has been conducted using a simple three dimensional model which assumes that the positions of petroleum migration pathways are controlled by the morphology of the sealing surfaces the modeling results have accurately predicted the petroleum occurrences and have been supported by petroleum geochemical studies most commercial petroleum accumulations are on the predicted preferential petroleum migration pathways ppmp formed by focusing of numerous small petroleum streams close to the kitchens and most large fields petroleum reserves greater than 1 10 8 ton have more than one preferential petroleum migration pathway to convey petroleum to the traps the focusing of petroleum originated from a large area of the generative kitchens into restricted channels is essential for the formation of large oilfields the strong porosity and permeability heterogeneities of the carrier beds and the relatively high prediction accuracy by a model that does not take into consideration of the effect of heterogeneity suggest that the positions of petroleum migration pathways in heterogeneous carrier beds in the lacustrine fault basins are determined primarily by the morphology of the sealing surfaces at regional scales

influence of co2 on melting of model granulite facies assemblages a model for the genesis of charnockites it is shown that partial melting studies at crustal pressures in sio2 rich portions of the system kalsio4 mg2sio2 h2o co2 can be used in modeling the anatectic origin of charnockites the univariant reaction phlogopite sanidine quartz vapor enstatite liquid yields an sio2 rich melt granite analog at 3 kbar the vapor composition at the solidus is buffered to high h2o contents by virtue of the coexistence of phlogopite with its breakdown products with higher pressures 8 and 15 kbar the fluid phase is buffered to higher co2 contents and the melt composition becomes enriched in k2o and mgo charnockite analog melting relations are controlled through the expansion of the quartz liquidus field relative to the enstatite and sanidine fields with increasing pressure it is noted that partial melts generated at the base of the crust in the presence of co2 rich fluid will be of an alkaline nature and will crystallize enstatite at lower pressures co2 saturated melting of similar sio2 rich bulk compositions phlogopite absent through the reaction enstatite sanidine quartz co2 liquid occurs at temperatures above 1000 c to about 15 kbar

geochemistry and origin of sour gas accumulations in the northeastern sichuan basin sw china significant natural gas reserves have recently been discovered in the lower triassic oolitic reservoirs from northeastern sichuan basin sw china in the wake of the december 2003 sour gas well blow out this study presents an overview on the petroleum geology and geochemistry of the sour gas accumulations in the study area two types of natural gas accumulations were identified in the lower triassic oolitic reservoirs both containing highly mature thermogenic gases with their hydrocarbon source rocks in upper permian strata natural gases from the area south of the ancient kaijiang liangping seaway are generally sweet gases formed as the result of thermal maturation whereas those discovered from north of the seaway are products of both thermal maturation and thermochemical sulfate reduction of early accumulated oils in the feixianguan formation reservoirs the proposed origins of the gases are supported by their chemical and stable carbon isotope compositions as well as the presence or absence of pyrobitumens in the reservoir the distribution of gas accumulations is controlled predominantly by the combination of lithologic and structural factors the regional variation in the concentrations of h2s in the gases appears related to the presence and thickness of anhydrite bearing evaporitic rocks interbedded or intercalated with the oolitic reservoirs

differential transport of co2 and ch4 in coalbed aquifers implications for coalbed gas distribution and composition coalbed gas content and composition are critical for the successful exploration and production of coalbed methane we investigated the differential transport of a preadsorbed co2 ch4 gas mixture along a coalbed aquifer by groundwater flow or across a coal bed by upward diffusion through pore water consistent analytical approximations and numerical solutions were obtained for typical cases the results suggest that differential transport of ch4 and co2 in a water saturated coal seam is mainly controlled by their adsorption equilibrium in coals and solubilities in water although co2 is about 20 times more soluble than ch4 in water at temperatures lower than 50c the transport of co2 from a coal seam is only several times more efficient than that of ch4 because of the stronger adsorption of co2 than ch4 in coals preferential transport of co2 over ch4 by groundwater advection can substantially accumulate more gas rich in co2 at downstream or near discharge zones if gas trapping structures exist and it may cause low total gas content of ch4 near recharge zones which may explain the co2 and ch4 distribution in the san juan and powder river basins and the undersaturation of gas in many other coals the separation and redistribution of coalbed gas by transport processes may also be complicated by late stage biogenic gas generation with infiltration of meteoric water with nutrients and gas producing microbes into the coal beds as suggested for some basins overall hydrogeologic systems strongly influence the distribution of coalbed gas content and composition in coal seams

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

hydrofracturing and episodic fluid flow in shale rich basins a numerical study low permeability sedimentary rocks commonly are fractured direct examination of exposed rock faces and drill cores shows evidence of hydrofracturing the mechanism for hydrofracturing its effects on fluid migration and its dependence on sediment permeability sedimentation rate and sedimentary sequences have not been explored in this study we carry out systematic numerical experiments to study the compaction induced hydrofracturing we show that the compaction induced hydrofracturing commonly may occur in shale rich basins and in sand shale sequences the frequency of such hydrofracturing depends on sediment permeability sedimentation rate and sedimentary sequence an important result is that compaction induced hydrofracturing may occur at relatively shallow depths in shale rich basins but it may mobilize enhanced fluid flow throughout the sedimentary basin over 60 of the total compaction induced fluid flow in the basin may be expelled during hydrofracturing we test the model against field data from the yinggehai basin of the south china margin where abundant hydrofractures in the uppermost quaternary marine mud have been recently detected by seismic imaging we suggest that the compaction induced hydrofracturing may mobilize fluid flow at great depths and affect hydrocarbon migration in shale rich basins

hierarchies of overpressure retardation of organic matter maturation case studies from petroleum basins in china the effects of overpressure on different aspects of organic matter maturation have been examined in three basins using multiple parameters overpressure in the yinggehai basin has retarded kerogen maturation hydrocarbon generation and thermal cracking of long chain normal hydrocarbons as well as evolution of isoprenoid hydrocarbons overpressure in the dongpu depression bohai bay basin seems to have retarded the maturation of bulk kerogens reflected by rock eval tmax the thermal cracking of long chain normal hydrocarbons and the evolution of isoprenoid hydrocarbons but seems to have had no detectable effects on vitrinite reflectance overpressure in the qiongdongnan basin has had no detectable retardation effects on all aspects of organic matter maturation the observed phenomena suggest differential retardation of organic matter maturation that is different organic matter maturation reactions and different maturity parameters have been retarded by overpressure to different degrees in the same overpressured system and four hierarchies of overpressure retardation hierarchy i retardation is defined as the state where the overpressure has retarded all aspects of organic matter maturation and is proposed to have been caused by the combination of high formation pressure and excess pressure a high water organic matter ratio and strong retention of reaction products in an early developed strong persistent overpressured system hierarchy ii retardation refers to the case in which all aspects of organic matter maturation except the maturation of hydrogen poor kerogens especially vitrinite have been retarded and seem to have been caused by early developed moderate to strong persistent overpressure hierarchy iii retardation refers to the situation where overpressure has retarded only the thermal cracking of liquid hydrocarbons but has had no detectable effect on the maturation of both hydrogen rich and hydrogen poor kerogens and is proposed to have been caused by moderate to strong persistent overpressures that began to develop around peak oil generation hierarchy iv retardation is defined as the situation where overpressure has had no detectable retardation on all aspects of organic matter maturation and may have been caused by cases wherein the overpressure developed too late the intensity of the overpressure was too low the duration of the overpressure was too short or overpressured fluids had been expelled frequently resulting from both the diversities of organic matter maturation reactions and the complexities of overpressure generation and development the hierarchies of overpressure retardation in different basins may be quite different and it is necessary to use multiple parameters to understand the evolution of the petroleum systems in overpressured basins

natural fractures in the barnett shale and their importance for hydraulic fracture treatments gas production from the barnett shale relies on hydraulic fracture stimulation natural opening mode fractures reactivate during stimulation and enhance efficiency by widening the treatment zone knowledge of both the present day maximum horizontal stress which controls the direction of hydraulic fracture propagation and the geometry of the natural fracture system which we discuss here is therefore necessary for effective hydraulic fracture treatment design we characterized natural fractures in four barnett shale cores in terms of orientation size and sealing properties we measured a mechanical rock property the subcritical crack index which governs fracture pattern development natural fractures are common narrow 0 05 mm 0 002 in sealed with calcite and present in en echelon arrays individual fractures have high length width aspect ratios 1000 1 they are steep 75 and the dominant trend is west northwest other sets trend north south the narrow fractures are sealed and cannot contribute to reservoir storage or enhance permeability but the population may follow a power law size distribution where the largest fractures are open the subcritical crack index for the barnett shale is high indicating fracture clustering and we suggest that large open fractures exist in clusters spaced several hundred feet apart these fracture clusters may enhance permeability locally but they may be problematic for hydraulic fracture treatments the smaller sealed fractures act as planes of weakness and reactivate during hydraulic fracture treatments because the maximum horizontal stress trends northeast southwest and is nearly normal to the dominant natural fractures reactivation widens the treatment zone along multiple strands

microbial production and modification of gases in sedimentary basins a geochemical case study from a devonian shale gas play michigan basin an expanded data set for gases produced from the antrim shale a devonian black shale in the michigan basin united states has allowed for a detailed examination of the related chemical and isotopic compositional changes in the solid gas liquid systems that discriminate between microbial and thermogenic gas origin in the antrim shale economic microbial gas deposits are located near the basin margins where the shale has a relatively low thermal maturity and fresh water infiltrates the permeable fracture network the most compelling evidence for microbial generation is the correlation between deuterium in methane and coproduced water along the basin margins there is also a systematic enrichment in 13c of ethane and propane with decreasing concentrations that suggests microbial oxidation of these thermogenic gas components microbial oxidation accounts not only for the shift in 13c values for ethane but also in part for the geographic trend in gas composition as ethane and higher chain hydrocarbons are preferentially removed this oxidation is likely an anaerobic process involving a syntrophic relationship between methanogens and sulfate reducing bacteria the results of this study are integrated into a predictive model for microbial gas exploration based on key geochemical indicators that are present in both gas and coproduced water one unequivocal signature of microbial methanogenesis is the extremely positive carbon isotope values for both the dissolved inorganic carbon in the water and the coproduced co2 gas in contrast the 13c value of methane is of limited use in these reservoirs as the values typically fall between the commonly accepted fields for thermogenic and microbial gas in addition the confounding isotopic and compositional overprint of microbial oxidation increasing the values to typically thermogenic values may obscure the distinction between methanogenic and thermogenic gas

pore throat sizes in sandstones tight sandstones and shales pore throat sizes in siliciclastic rocks form a continuum from the submillimeter to the nanometer scale that continuum is documented in this article using previously published data on the pore and pore throat sizes of conventional reservoir rocks tight gas sandstones and shales for measures of central tendency mean mode median pore throatsizes diameters are generally greater than2 mm in conventionalreservoir rocks range from about 2 to 0 03 mm in tight gas sandstones and rangefrom0 1to0 005 mminshales hydrocarbonmolecules asphaltenes ring structures paraffins and methane form another continuum ranging from 100 a 0 01 mm for asphaltenes to 3 8 a 0 00038 mm for methane the pore throat size continuum provides a useful perspective for considering 1 the emplacement of petroleum in consolidated siliciclastics and 2 fluid flow through fine grained source rocks now being exploited as reservoirs

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

episodic fluid expulsion from geopressured sediments numerical simulation of fluid explusion from geopressured sediments using a one dimensional finite difference model shows that large volumes of fluid can be transported through a fractured seal during short lived 100 year expulsion events in this model abnormal fluid pressures are maintained by an impermeable seal when the fluid pressure exceeds 85 of the lithostatic pressure a vertical fracture opens in the seal providing a permeable pathway from the geopressured sediments into the overlying section fluid pressure in the seal decreases as fluid flows through the fracture closing the fracture as sediments in the seal compact once the fracture closes the seal remains impermeable until fluid flowing from deeper in the section increases fluid pressure to the fracture criteria a process that takes 10 000 500 000 years fractures emplaced in relatively incompressible seals such as compacted and or cemented sediments remain open for 20 50 years fluid fluxes through the seal integrated over the life of these events are 1 5 107 kg m2 and temperatures in the overlying sediments are increased by 5 20 c these temperature anomalies decay to less than half their original value in 300 years suggesting that the thermal anomalies observed in wells that are attributed to fluid expulsion formed in response to a very recent or currently active event

aggregate properties of fracture populations abstract empirical studies indicate that the individual attributes of both faults and extension fractures follow power law scaling aggregate properties of fracture populations are important in a variety of problems and can be specified in terms of the scaling parameters of individual fracture attributes development of an expression for an aggregate property requires consideration of a number of independent factors including the topologic dimension of the aggregate property the topologic dimension of sampling and the possibility of scaling changes for fractures that span some mechanically significant layer the riemann zeta function provides an alternative to integration for the analytical and numerical solution of aggregate problems previous work regarding aggregate properties of fracture populations has focused on the strain due to faulting new expressions are developed here for other aggregate properties of interest fracture surface area fracture porosity fracture permeability and shear wave anisotropy a general characteristic of these aggregate properties is that for most values of scaling exponents the aggregate properties are dependent on the size of the sampling domain this implies that the aggregate properties are scale dependent additionally it appears that fracture surface area is concentrated in the smallest fractures of many populations fracture porosity is concentrated in the largest fractures of most populations but not as strongly as fracture permeability which probably derives almost entirely from the largest fractures in populations

evidence for multiple stages of oil cracking and thermochemical sulfate reduction in the puguang gas field sichuan basin china the puguang gas field is the largest gas field found in marine carbonates in china marine carbonate reservoirs in this field were buried to a depth of about 7000 m 22 966 ft and experienced maximum temperature up to 220c before uplift to the present day depth of 5000 5500 m 16 404 18 045 ft with present day thermal maturity between 2 0 and 3 0 equivalent vitrinite reflectance ro sulfur rich pyrobitumens with reflectance up to 3 5 are widespread in the reservoirs and resulted from thermal cracking of crude oils most likely generated from upper permian source rocks and thermochemical sulfate reduction tsr natural gases in the puguang gas field have wide variations in nonhydrocarbon gas contents with h2s contents between 5 1 and 58 3 and co2 contents between 7 9 and 18 0 the hydrocarbon gases originated mainly from thermal cracking of accumulated oil but were altered by tsr thermochemical sulfate reduction in the study area exerted different effects on the isotope compositions of different hydrocarbon gas components at different tsr stages the differential increase of 13c values for different gas components reflects transformation from a heavy hydrocarbon gas dominated tsr stage to a methane dominated tsr stage this caused a decrease of 13cmethane13cethane values and a corresponding conversion from reversed to normal isotope distributions thermochemical sulfate reduction in the study area appears to have been limited by sulfate concentrations in the reservoirs a successive three stage tsr series namely liquid hydrocarbon involved tsr heavy hydrocarbon gas dominated tsr and methane dominated tsr occurred in reservoirs with sufficient sulfate concentration methane can be the dominant organic reactant for tsr but only at elevated temperature and after most c2 hydrocarbons are exhausted

geochemical characterization of gases from the mississippian barnett shale fort worth basin texas molecular and isotopic compositions of 51 gas and 7 condensate samples produced from the barnett shale were determined by gas chromatography isotope ratio mass spectrometry to investigate their origin and maturity at the time of generation additionally two hydrous pyrolysis experiments were performed to calibrate maturity values predicted for gas generation molecular and carbon and hydrogen isotopic compositions of the gases indicate that gas produced from the barnett is thermogenic to estimate generation maturity additional analyses were performed on the condensates and available core samples diamondoid indices combined with vitrinite reflectance ro measurements isotopic and molecular composition and hydrous pyrolysis experiments suggest that gas produced from the barnett shale was generated within the condensate wet gas window 1 3 2 0 ro at a later stage than hydrocarbons accumulated in shallower reservoirs the origin of the gas is thermogenic probably derived from both kerogen cracking and secondary cracking of previously generated nonmigrated hydrocarbons additionally the occurrence of a methane isotope reversal in group 1 gases corroborates that in situ oil or gas cracking is occurring in the easternmost part of the study area

lacustrine basin unconventional resource plays key differences abstract there has been a revival in hydrocarbon source rock characterization and development associated with growing interest in unconventional resources where these fine grained organic rich rocks act as both source and reservoir to date the exploration focus on shale reservoirs has been largely on marine systems lacustrine source rocks for conventional resources are geographically important dominating regions such as china indonesia and brazil s resource base however they have been generally untested for unconventional resources there are a number of key differences in the nature of these hydrocarbon systems that should be considered when assessing whether lacustrine systems may represent future unconventional opportunities in areas where the conventional resource base is dominated by lacustrine sourced oil among the key differences between these depositional systems is the greater sensitivity to high frequency climatic variability within lacustrine systems lacustrine systems are highly sensitive to changes in the balance between precipitation and evaporation which may lead to rapid changes in lake level potentially exceeding 600 m these changes in depositional conditions are geologically rapid and may occur over periods of thousands of years such changes can reduce the areal extent of potentially thick source rock intervals to only those portions of a basin where a permanent deep lake was present thus the core unconventional target area may be geographically limited compared with their marine counterpart although potentially areally limited a review of many lacustrine source rocks suggests that their thicknesses are often significantly greater than marine source rocks an examination of the more distal portions of lacustrine systems where better source rock potential is present reveals that there is generally limited connectivity between source and conventional reservoir in these settings such as the wind river basin waltman shale the hydrocarbons remain trapped within the shales potentially leading to over pressured hydrocarbon charged systems such conditions suggest that although areally limited viable unconventional targets may exist if suitable reservoir conditions are present finally the character of the oils produced is different in these settings with lacustrine oils being waxy and displaying different hydrocarbon generation and cracking kinetics high wax oils display distinct flow characteristics being more viscous and may offer different production challenges than their non waxy marine equivalents additionally differences in their cracking kinetics may indicate that the timing of gas generation for shale gas plays may differ significantly from marine systems

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

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

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

origin and mechanism of the formation of the low oil saturation moxizhuang field junggar basin china implication for petroleum exploration in basins having complex histories the moxizhuang field is a small oil field in the central junggar basin containing several low saturation low resistivity oil reservoirs which display a complex correlation between oil saturation and porosity and permeability that is atypical of both the filled and drained reservoirs biomarker associations of crude oil and grains containing oil inclusions gois of both the present day water bearing zones water zones and the oil and water bearing zones low oil saturation pay zones were analyzed to investigate the mechanisms for the formation of the low saturation low resistivity oil accumulations the biomarker assemblage and hierarchical cluster analysis indicate that oil in the moxizhuang field was mostly generated from permian source rock deposited in brackish to hypersaline anoxic environments the pay zones and several water zones display goi values as much as 38 greater than the generally accepted threshold goi value for an oil column 5 these goi values are similar to those for high saturation oil reservoirs in the bohai bay basin and oil zone samples from australian basins suggesting that both pay zones and water zones were high saturation oil reservoirs in the geologic past geologic history analysis shows that the moxizhuang field was located on the north wing of a paleoanticline during oil charge in the late cretaceous to paleogene this anticline has gradually evolved into a south dipping monocline since the neogene causing northward remigration of accumulated oil differential lateral leakage of accumulated oil in different sandstone layers during the remigration phase led to the formation of the water zones with high goi values completely drained reservoirs and the low saturation low resistivity pay zones partially preserved reservoirs and caused the complex correlation between oil saturation and porosity and permeability compared with other postaccumulation physicochemical alteration processes lateral leakage has rarely been recognized recognizing differential lateral leakage of accumulated petroleum with the existence of high quality unfaulted cap rocks has important implication for petroleum exploration in sedimentary basins having complex evolution histories

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

pore types in the barnett and woodford gas shales contribution to understanding gas storage and migration pathways in fine grained rocks the identification of organoporosity microscale and nanoscale pores within organic matter in shales its importance to storage and perhaps transfer of gas molecules through shales and methods for gathering three dimensional images of the pores such as by argon ion milling and or field emission scanning electron microscopy have all been well documented and discussed for unconventional gas shales however other types of pores exist within shales that can be important to storage and migration of gas and oil and other technologies are available for their identification and imaging the different pore types found in the barnett and woodford shales are described and classified in this article scanning electron microscopy revealed the presence of porous floccules in both the barnett and woodford shales which appear similar to laboratory produced floccules and to those in other ancient shales published experimental and observational studies indicate that floccules are hydraulically equivalent to coarser grains and are transported by traction processes current induced microsedimentary structures and textures within the barnett and woodford shales as well as the preserved floccules suggest such processes were active during transport and deposition pore spaces between the floccules are open and can provide storage space as well as permeability pathways for gas molecules through the shales pores are also found within organic matter that occurs both as discrete particles and as adsorbed coatings around clay grains in the shale they are referred to here as organopores porous fecal pellets are also common in the barnett shale preserved fossil fragments such as organic walled spores and inorganic sponge spicules have hollow central chambers which may remain partially or completely open even after burial intraparticle pores occur between grains of various minerals e g pyrite framboids microchannels within shale matrix which may be the bounding surfaces of scours or microsedimentary structures may also provide permeability pathways for hydrocarbon migration mircrofractures are also common and their initiation might be related to mineral crystal structure when present in sufficient quantity these pore types offer potential gas and oil molecule storage spaces and permeability pathways through the shales

differential fluid migration behaviour and tectonic movement in lower silurian and lower cambrian shale gas systems in china using isotope geochemistry abstract isotope geochemistry has been introduced as a means to trace origin of the hydrocarbon and characterize highly productive shale gas systems recently to assess the impact of tectonic movement and the sealing of shale gas systems isotope geochemistry pressure coefficients and the distribution of bitumens are analysed many samples yield isotope geochemical data with typical carbon isotopic reversals 13 c 1 13 c 2 and hydrogen isotopic reversals 13 d c2h6 13 d ch4 in the lower silurian shale gas isotopically reversed gases are considered to originate in sealed self contained petroleum systems besides isotope reversals order degree of shale gas has positive correlation with gas production isotopically normal gases from the lower cambrian indicate that this formation was a continued relatively open petroleum system when oil and gas generated the pressure coefficients of the lower silurian shale gas reservoir range from 1 45 to 2 03 indicating that the reservoir is overpressurized whereas the lower cambrian shale gas reservoir possesses a normal pressure system overpressurization of the lower silurian shale gas reservoir also indicates that it is a well sealed system the distribution and isotope geochemistry of bitumens in the sinian dolomite and cambrian shale suggests that the source rock of the sinian hydrocarbon is the cambrian shale an unconformity induced from tectonic movement during the tongwan period is interpreted to be the fluid migration tunnel and the cause of the differential shale gas content and production finally the isotopic reversals associated with maturity pressure coefficients and tectonic evolution can both assess the preservation conditions of the reservoir and explain the differential fluid migration behaviour

geological controls on coalbed methane reservoir capacity and gas content the influence of coal composition and rank on coalbed methane reservoir capacity gas content and gas saturation have been investigated for a series of australian canadian and united states coals globally there is no or little correlation between coal rank and methane adsorption capacity as commonly assumed although in particular basins there are general trends with rank and composition micropore1 capacity and surface area determined from low pressure carbon dioxide adsorption isotherms 0 c decrease and then increase with rank passing through a minimum in the high volatile bituminous coal rank there is no consistent variation in modal micropore size or size distribution with rank for suites of isorank coals there is a poor permian bulli and wongawilli seams australia to good positive correlation gates formation coal seams lower cretaceous canada between vitrinite content and methane adsorption capacity dry ash free and as received bases for each isorank coal suite there is a good correlation between micropore capacity and abundance of vitrinite and high pressure methane adsorption capacity comparison of coals of similar composition but from different isorank suites indicates however that the coals with the highest methane adsorption capacity do not necessarily have the highest micropore capacity such results are counterintuitive most pore volume available for methane adsorption is generally assumed to be microporosity it is suspected that moisture prevents methane from accessing some microporosity or competes with methane for adsorption space carbon dioxide micropore capacity which is performed on a dry basis may thus not reflect the microporosity available for gas adsorption in moisture equilibrated coals alternatively because of differing physical and chemical properties of carbon dioxide and methane apparent microporosity available to carbon dioxide due to greater energy of adsorption may not be available to methane total desorbed gas from canister analyses of sydney basin australian coals suggests that most coals are under saturated for a small data set the degree of saturation is negatively correlated with permeability r 0 78 suggesting preferential gas leakage from the higher permeability coals which are vitrite rich some degree of under saturation is probably the result of increased reservoir capacity as a consequence of uplift of the coal seams and thus lower temperatures following gas generation rates of desorption are correlated with total gas content r 0 79 but do not correlate with rank or any compositional parameter

identification of microbial and thermogenic gas components from upper devonian black shale cores illinois and michigan basins differentiation of microbial versus thermogenic methane in coalbed and black shale accumulations can affect strategies for exploration and may influence the total gas content in a given area early identification of these processes from crushed core materials even before formation fluids and produced gas samples are available could permit a more efficient and cost effective exploration total gas contents and compositional and isotopic data from new albany shale core materials are presented which delineate regional occurrence of microbial thermogenic and mixed gas generation in the illinois basin these trends are consistent with those identified from detailed prior studies of produced gas and water chemistry from the same locations the most useful markers for microbial gas in crushed core gases are elevated co2 contents characterized by high values 5 core gas analyses from wells in which microbial gas is identified commonly have significantly more total gas absorbed than do core samples from wells producing gases solely of thermogenic origin these observations are independent of variations in sample depth and organic carbon content in a given core thus this integrated case study of core and produced gases in the illinois basin illustrates that the areas containing microbial gas in addition to early thermogenic gas may be more productive than pure thermogenic zones for these early to immature unconventional gas deposits

experimental mechanical compaction of clay mineral aggregates changes in physical properties of mudstones during burial dry and brine saturated clay aggregates ranging from pure smectite to pure kaolinite were compacted in the laboratory experiments were conducted by increasing vertical effective stress up to 50 mpa to study the changes in physical properties of mudstones during burial the results suggest that the physical properties porosity density acoustic velocity etc of mudstones vary greatly with increasing effective stress clay mineralogy and fluid content kaolinite aggregates are much more compressible than those composed of smectite brine saturated clay mixtures are much more compressible than dry clay mixtures brine may soften and lubricate the clay matrix compared to dry clays resulting in higher compressibility in the brine saturated state the lesser degree of compaction of dry smectite compared to dry kaolinite aggregates can be explained by the differences in grain size as kaolinitic clays have much larger grains than smectitic clays the extremely fine grained nature of smectite implies that the imposed vertical stress is distributed over a very large number of grain contacts so that the force per contact area is very low in smectite compared to that in coarse grained kaolinite at 20 mpa effective stress corresponding to about 2 km burial depth with hydrostatic pore pressure brine saturated pure kaolinite compacted to 20 porosity while pure smectite retained 41 porosity brinesaturated clay mixtures show higher vp and lower vs than dry clay mixtures a pronounced difference in vs was observed among the brinesaturated clay mixtures the lowest vs as a function of vertical effective stress was found for pure smectite for a given porosity value smectitic clays have higher velocities and elastic moduli than the kaolinitic clays the vp vs ratio is significantly higher in smectite than in kaolinite aggregates treating mudstones as a uniform class of rocks introduces significant errors in estimates of physical properties which are strongly affected by the clay mineralogy grain size the amount of other minerals present and fluid content our results have implications for well log interpretation and mudstone and shale property determinations from seismic data at shallow burial depth o 2k m 801c above depths where significant chemical compaction takes place r 2007 elsevier ltd all rights reserved

merging sequence stratigraphy and geomechanics for unconventional gas shales the recent revelation of vast global quantities of potentially gas and oil productive shales has paved the way for rapid advancements in understanding their geological properties many of which affect their geomechanical properties and ultimately reservoir operations and performance because of shale s unique and very intricate geological physical and mechanical properties at all scales from nano to macro scale abousleiman et al 2010 compared with sandstones and carbonates the ad jective unconventional has often been applied to their characterization although many shale characteristics are different than those of sandstones and carbonates and require new technologies to measure them other characteristics mentioned below are similar as such customized conventional methodologies and concepts can be applied to exploration and production of shale gas and oil

characterization of shale pore system a case study of paleogene xin gouzui formation in the jianghan basin china abstract the pore size classification micropore 50 nm of iupac 1972 has been commonly used in chemical products and shale gas reservoirs however it may be insufficient for shale oil reservoirs to establish a suitable pore size classification for shale oil reservoirs the open pore systems of 142 chinese shales from jianghan basin were studied using mercury intrusion capillary pressure analyses a quantitative evaluation method for i micropores 0 25 nm in diameter ii micropores 25 100 nm mesopores 100 1000 nm and macropores 1000 nm within shales was established from mercury intrusion curves this method was verified using fractal geometry theory and argon ion milling scanning electron microscopy images based on the combination of pore size distribution with permeability and average pore radius six types i vi shale open pore systems were analyzed moreover six types open pore systems were graded as good medium and poor reservoirs the controlling factors of pore systems were also investigated according to shale compositions and scanning electron microscopy images the results show that good reservoirs are composed of shales with type i ii and iii pore systems characterized by dominant mesopores mean 68 12 vol a few macropores mean 7 20 vol large porosity mean 16 83 an average permeability of 0 823 md and an average pore radius r a of 88 nm type iv pore system shales are medium reservoirs which have a low oil reservoir potential due to the developed ii micropores mean 57 67 vol and a few of mesopores mean 20 19 vol poor reservoirs composed of type v and vi pore systems are inadequate reservoirs for shale oil due to the high percentage of i micropores mean 69 16 vol which is unfavorable for the flow of oil in shale pore size is controlled by shale compositions including minerals and organic matter and arrangement and morphology of mineral particles resulting in the developments of shale pore systems high content of siliceous mineral and dolomite with regular morphology are advantage for the development of macro and mesopores while high content of clay minerals results in a high content of micropores

fractured shale gas systems the first commercial united states natural gas production 1821 came from an organic rich devonian shale in the appalachian basin understanding the geological and geochemical nature of organic shale formations and improving their gas producibility have subsequently been the challenge of millions of dollars worth of research since the 1970s shale gas systems essentially are continuous type biogenic predominant thermogenic or combined biogenic thermogenic gas accumulations characterized by widespread gas saturation subtle trapping mechanisms seals of variable lithology and relatively short hydrocarbon migration distances shale gas may be stored as free gas in natural fractures and intergranular porosity as gas sorbed onto kerogen and clay particle surfaces or as gas dissolved in kerogen and bitumen five united states shale formations that presently produce gas commercially exhibit an unexpectedly wide variation in the values of five key parameters thermal maturity expressed as vitrinite reflectance sorbed gas fraction reservoir thickness total organic carbon content and volume of gas in place the degree of natural fracture development in an otherwise low matrix permeability shale reservoir is a controlling factor in gas producibility to date unstimulated commercial production has been achievable in only a small proportion of shale wells those that intercept natural fracture networks in most other cases a successful shale gas well requires hydraulic stimulation together the devonian antrim shale of the michigan basin and devonian ohio shale of the appalachian basin accounted for about 84 of the total 380 bcf of shale gas produced in 1999 however annual gas production is steadily increasing from three other major organic shale formations that subsequently have been explored and developed the devonian new albany shale in the illinois basin the mississippian barnett shale in the fort worth basin and the cretaceous lewis shale in the san juan basin in the basins for which estimates have been made shale gas resources are substantial with in place volumes of 497 783 tcf the estimated technically recoverable resource exclusive of the lewis shale ranges from 31 to 76 tcf in both cases the ohio shale accounts for the largest share

modeling of gas generation from the barnett shale fort worth basin texas the generative gas potential of the mississippian barnett shale in the fort worth basin texas was quantitatively evaluated by sealed gold tube pyrolysis kinetic parameters for gas generation and vitrinite reflectance ro changes were calculated from pyrolysis data and the results used to estimate the amount of gas generated from the barnett shale at geologic heating rates using derived kinetics for ro evolution and gas generation quantities of hydrocarbon gas generated at ro 1 1 are about 230 l t 7 4 scf t and increase to more that 5800 l t 186 scf t at ro 2 0 for a sample with an initial total organic carbon content of 5 5 and ro 0 44 the volume of shale gas generated will depend on the organic richness thickness and thermal maturity of the shale and also the amount of petroleum that is retained in the shale during migration gas that is reservoired in shales appears to be generated from the cracking of kerogen and petroleum that is retained in shales and that cracking of the retained petroleum starts by ro 1 1 this result suggests that the cracking of petroleum retained in source rocks occurs at rates that are faster than what is predicted for conventional siliciclastic and carbonate reservoirs and that contact of retained petroleum with kerogen and shale mineralogy may be a critical factor in shale gas generation shale gas systems together with overburden can be considered complete petroleum systems although the processes of petroleum migration accumulation and trap formation are different from what is defined for conventional petroleum systems

morphology genesis and distribution of nanometer scale pores in siliceous mudstones of the mississippian barnett shale research on mudrock attributes has increased dramatically since shale gas systems have become commercial hydrocarbon production targets one of the most significant research questions now being asked focuses on the nature of the pore system in these mudrocks our work on siliceous mudstones from the mississippian barnett shale of the fort worth basin texas shows that the pores in these rocks are dominantly nanometer in scale nanopores we used scanning electron microscopy to characterize barnett pores from a number of cores and have imaged pores as small as 5 nm key to our success in imaging these nanopores is the use of ar ion beam milling this methodology provides flat surfaces that lack topography related to differential hardness and are fundamental for high magnification imaging nanopores are observed in three main modes of occurrence most pores are found in grains of organic matter as intraparticle pores many of these grains contain hundreds of pores intraparticle organic nanopores most commonly have irregular bubblelike elliptical cross sections and range between 5 and 750 nm with the median nanopore size for all grains being approximately 100 nm internal porosities of up to 20 2 have been measured for whole grains of organic matter based on point count data from scanning electron microscopy analysis these nanopores in the organic matter are the predominant pore type in the barnett mudstones and they are related to thermal maturation nanopores are also found in bedding parallel wispy organic rich laminae as intraparticle pores in organic grains and as interparticle pores between organic matter but this mode is not common although less abundant nanopores are also locally present in fine grained matrix areas unassociated with organic matter and as nano to microintercrystalline pores in pyrite framboids intraparticle organic nanopores and pyrite framboid intercrystalline pores contribute to gas storage in barnett mudstones we postulate that permeability pathways within the barnett mudstones are along bedding parallel layers of organic matter or a mesh network of organic matter flakes because this material contains the most pores

isotopic reversal rollover in shale gases produced from the mississippian barnett and fayetteville formations abstract ethane propane and carbon dioxide show reversed carbon isotopic maturity trends in natural gas produced from the barnett and fayetteville shales at thermal maturities greater than 1 5 vre at this high level of thermal maturity the iso butane to n butane ratio also reverses suggesting wet gas cracking has occurred generating more gas molecules in the same volume resulting in overpressure and increased stabilized production rates in the barnett hydrothermal fluids from the nearby ouachita thrust front apparently enhanced the maturity of the fayetteville and barnett shales water hydrocarbon reactions at these high maturities may account for the isotopic reversals

oil and gas geochemistry and petroleum systems of the fort worth basin detailed biomarker and light hydrocarbon geochemistry confirm that the marine mississippian barnett shale is the primary source rock for petroleum in the fort worth basin north central texas although contributions from other sources are possible biomarker data indicate that the main oil generating barnett shale facies is marine and was deposited under dysoxic strong upwelling normal salinity conditions the analysis of two outcrop samples and cuttings from seven wells indicates variability in the barnett shale organic facies and a possibility of other oil subfamilies being present light hydrocarbon analyses reveal significant terrigenous sourced condensate input to some reservoirs resulting in terrigenous and mixed marine terrigenous light hydrocarbon signatures for many oils the light hydrocarbon data suggest a secondary condensate generating source facies containing terrigenous or mixed terrigenous marine organic matter this indication of a secondary source rock that is not revealed by biomarker analysis emphasizes the importance of integrating biomarker and light hydrocarbon data to define petroleum source rocks gases in the fort worth basin are thermogenic in origin and appear to be cogenerated with oil from the barnett shale although some gas may also originate by oil cracking isotope data indicate minor contribution of biogenic gas except for reservoirs in the pennsylvanian bend group which contain gases spanning the complete range of observed maturities the gases appear to be stratigraphically segregated younger reservoirs contain less mature gas and older reservoirs contain more mature gas we cannot rule out the possibility that other source units within the fort worth basin such as the smithwick shale are locally important petroleum sources

shale gas desorption behavior and carbon isotopic variations of gases from canister desorption of two sets of gas shales in south china abstract four shale samples from the lower silurian longmaxi formation and the lower cambrian shuijingtuo formation in the eastern part of chongqing sw china were subjected to canister desorption experiments at reservoir and elevated temperatures up to 90 c to investigate shale gas release behaviors and their variations in chemical and isotopic compositions of desorbed gases both the ratios of gas released at reservoir temperature to the total desorbed gas at reservoir and elevated temperatures and the desorption rates suggest that the longmaxi shale gas is more easily released than the shuijingtuo shale gas scanning electron microscope sem observation along with low temperature co2 and n2 adsorption results suggests that organic matter hosted pores with diameters of 2 100 nm are rich in the longmaxi shales whereas well developed micropores