experimental study of fluid transport processes in the matrix system of the european organic rich shales i scandinavian alum shale abstract this contribution presents results from a laboratory study investigating the fluid gas water transport properties in the matrix system of the scandinavian alum shale the maturity of the organic matter of the shale samples ranged between 0 5 and 2 4 vitrinite reflectance vr r gas he ar ch 4 and water flow properties were determined at effective stresses ranging between 5 and 30 mpa and a temperature of 45 c the effects of different controlling factors parameters on the fluid conductivity including permeating fluid moisture content anisotropy heterogeneity effective stress pore pressure and load cycling were analyzed and discussed pore volume measurements by helium expansion were conducted under controlled in situ effective stress conditions on a limited number of plugs drilled parallel and perpendicular to bedding for alum shale the intrinsic permeability coefficients measured parallel and perpendicular to bedding 6 10 22 8 10 18 m 2 were within the range previously reported for other shales and mudstones permeability coefficients were strongly dependent on permeating fluid moisture content anisotropy effective stress and other sample to sample variations the intrinsic absolute permeabilities measured with helium were consistently higher up to five times than those measured with argon and methane permeability coefficients he ch 4 measured on a dry sample were up to six times higher than those measured on an as received sample depending on effective stress the effect of moisture on measured permeability coefficients became more significant as effective stress increased permeability coefficients he ch 4 measured parallel to bedding were up to more than one order of magnitude higher than those measured perpendicular to bedding parallel to bedding all samples showed a nonlinear reduction in permeability with increasing effective stress 5 30 mpa the stress dependence of permeability could be well described by an exponential relationship

accessibility and mobility of hydrocarbons in lacustrine shale solvent flow through extraction experiments on eocene oil shales from bohai bay basin eastern china abstract in order to examine the mobility of hydrocarbons in a lacustrine shale oil system three cylindrical core plugs from the eocene shahejie formation lacustrine shale oil system in the jiyang depression were sequentially extracted with dichloromethane dcm in flow through experiments under controlled stress conditions in a tri axial flow cell orientations of the three sample plugs were perpendicular to bedding 1 and parallel to bedding 2 and 3 post experiment micro ct analysis confirmed three different flow patterns cross bedding flow 1 minor bedding parallel flow 2 and extensive bedding parallel flow along open fractures 3 extraction times were 28 days 7 days and 3 days for samples 1 2 and 3 respectively sequential series of extracts from the samples were analyzed using gas chromatography for comparison hydrocarbon compositions were also determined on bulk extracts of powdered original sister sample material and the residues after flow through experiments the mobilities of hydrocarbons are controlled by the flow direction and fracture intensity and orientations for sample 1 dcm flow through extraction yielded mostly hydrocarbons associated with matrix kerogen this flow extracted bitumen was found to be much heavier than that extracted from the other two samples and to have a lower mobility the hydrocarbons extracted from the sample 2 were the lightest for sample 3 containing micro fractures along the bedding planes the extraction process was apparently very effective not only dissolving hc from the fractures but also some hc from the kerogen the characteristic hydrocarbon compositions of the samples were essentially retained in all extracts although lighter hydrocarbons

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

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

geochemistry of petroleum systems in the niuzhuang south slope of bohai bay basin part 1 source rock characterization detailed mapping of the tertiary strata of the dongying depression bohai bay basin reveals that oil shales and dark mudstones in the es4 and es3 members of the eocene oligocene shahejie formation have excellent potential as petroleum source rocks regional distributions of total organic carbon content kerogen type and thermal maturation indicate that abundant mature source rocks are present in the niuzhuang sag whereas source rocks along the niuzhuang south slope are currently immature or marginally mature for the generation of conventional oils this study examined the molecular characteristics for a number of biomarker compound classes and related these to either source facies change or different burial and thermal maturation an important observation made during this study is the significant variation in the relative distributions and absolute concentrations of a wide range of aliphatic and aromatic hydrocarbon markers in the rock extracts as a function of burial depth this variation may potentially explain the uncertainty associated with the maturity assessment and genetic modeling for so called immature oils that are usually defined on the basis of alkane biomarker isomerization ratios and the presence of biomarkers with biological configurations

quantitative refinement of calibrated 14c distributions abstract a new method is presented for using known ordering or other relationships between 14c samples to reduce 14c dating uncertainty the order of sample formation is often known from for example stratigraphic superposition dendrochronology or crosscutting field relations constraints such as a minimum time between dates and limits from historical information are also readily included dendrochronologically calibrated calendric date histograms initially represent each date the method uses bayes theorem and the relational constraints to upweight date ranges in each date distribution consistent with the other date distributions and the constraints and downweight unlikely portions the reweighted date distributions retain all dating possibilities present in the initial calibrated date distributions but each date in the result now reflects the extra information such as ordering supplied through the constraints in addition one may add information incrementally and thus analyze systematically its effect on all the date distributions thus the method can be used to assess the consistency of the quantitative data at hand the bayesian approach also uses the empirical calibrated date distributions directly so information is not lost prematurely by summarized dates to a mean and variance or confidence intervals the approach is illustrated with data from two densely sampled paleoseismic sites on the san andreas fault in southern california an average reduction in 14 c date distribution variance of 59 is achieved using ordering information alone and 85 is achieved by also applying sedimentation rate constraints and historical information

flow through extraction of oil and gas shales under controlled stress using organic solvents implications for organic matter related porosity and permeability changes with thermal maturity abstract four core plugs from the lower jurassic posidonia shale of the hils syncline in northern germany have been subjected to flow through extraction tests with dichloromethane dcm under controlled stress conditions in a tri axial flow cell the samples represent a maturity sequence from 0 53 to 1 45 vrr the bitumen sequentially extracted from the natural pore space of the shale plugs was analyzed for its geochemical composition changes in rock matrix density porosity and permeability resulting from the removal of soluble organic matter were determined the relative porosity increase of the plugs after extraction ranged from 6 to 13 and correlated with the extract yield klinkenberg corrected permeability coefficients measured with helium increased by a factor of 17 0 for the immature early mature sample and 26 6 for the overmature sample petrographical investigations after extraction indicate that fluid flow occurred predominantly parallel to bedding as evidenced by open fractures and fractures bearing residues that apparently precipitated from the dcm solution compositional variations of the extracts over time are interpreted in terms of the organic geochemical inventory of bitumen associated with the natural pore system and its accessibility at different maturity levels these patterns deviate strongly from the bulk rock extracts of the powdered samples

guidelines for evaluating petroleum source rock using programmed pyrolysis rock eval pyrolysis is used to rapidly evaluate the petroleum generative potential and thermal maturity of rocks accurate conclusions require programs every 30 60 ft 9 18 m understanding of interpretive pitfalls and supporting data such as visual kerogen vitrinite reflectance and elemental analyses the generative potential of coals is commonly overestimated by pyrolysis and is best determined by elemental analysis and organic petrography most coals show high s2 s3 5 and low hi values 300 mg hc g toc migrated oil and mud additives which alter rock eval data can sometimes be removed by special processing for immature rocks bimodal s2 peaks and pi values over 0 2 indicate contamination pyrolysis downgrades organic poor clay rich rocks which show lower hi and higher tmax values than isolated kerogen because of adsorption of pyrolyzate on the clays tmax values for small s2 peaks 0 2 mg hc g toc are unreliable tmax is affected by maturation organic matter type contamination and the mineral matrix s3 is sensitive to inorganic and adsorbed carbon dioxide and to instrumentation problems acidification of carbonate rich samples and proper maintenance improves s3 measurement constant sample weights 100 mg are recommended below a threshold weight tmax increases by up to 10 c and other parameters decrease organic rich samples which overload the detector can be diluted with carbonate detector linearity is determined by pyrolyzing various weights of an organic rich rock

paleomagnetic measurement of nonbrittle coseismic deformation across the san andreas fault at pallett creek paleomagnetic data have been obtained to address a problem at the pallett creek paleoseismological site the 9 mm yr slip rate determined from three dimensional mapping of late holocene offsets across discrete faults is only a quarter of the expected value we suspected that nonbrittle deformation adjacent to the faults might account for the 26 mm yr discrepancy in our search for the missing slip we collected and analyzed 264 paleomagnetic samples from a 53 m wide transect across the fault zone half the samples came from a unit deposited immediately after a large earthquake of about a d 1480 these samples were affected by two large earthquakes that involved rupture at the site in 1812 and 1857 we collected the other half of the samples from a slightly older bed one that was deposited before the earthquake of about a d 1480 relative to control groups composed of 10 samples and collected 50 m from the fault samples closer to the fault display clockwise rotations of 30 or less if interpreted as block rotations the data from the older unit imply that it has sustained a total of 14 0 2 9 m of dextral warp during the past three major earthquakes and that the younger unit has experienced a total of 8 5 1 0 m of warp during the most recent two combining these values with the amounts of dextral slip across the mapped fault planes yields dextral offsets of 5 5 6 25 and 6 25 m for the events of a d 1480 1812 and 1857 and a slip rate of 35 6 6 7 mm yr this slip rate averaged over the past three complete seismic cycles is consistent with published rates from other sites offsets associated with the past three events are remarkably similar these amounts however appear independent of the length of interseismic cycles these observations suggest 1 that this part of the san andreas fault has a characteristic strength and 2 that conventional concepts of strain accumulation and relief for example time and slip predictable models of earthquake occurrence are unrealistic

petrographic and geochemical characterization of microfacies in a lacustrine shale oil system in the dongying sag jiyang depression bohai bay basin eastern china abstract petrology and rock eval analyses have been conducted in the lower third and upper fourth members lower es3 and upper es4 of the shahejie fm source rock intervals in well fanye1 in the dongying sag jiyang depression bohai bay basin eastern china the organic matter in rocks intersected by this well is dominated by lamalginite and bituminite and most samples contain type i or ii kerogen microfacies a h has been identified according to their organic mineral composition and structure using polished thin sections under microscopy the form and location of hydrocarbon residue occurrences mainly as solid bitumen with fluorescence are different in those microfacies microfacies a which is dominant in well fanye 1 is calcareous mudstone without lamination and the hydrocarbon residue is dispersed through the rock with some being present in subtle microfractures microfacies b and f are mostly composed of shale with adsorbed hydrocarbon indicated by fluorescence along mineral grains microfacies c is laminated argillaceous carbonate with hydrocarbon residue mainly occurring in thin microfractures along the bedding plane microfacies d and e are mainly carbonate and microfacies d is laminated with micrite and sparite and hydrocarbon residue occurrence is not only in the microfractures along the bedding but also in the micropores among the grains in the sparite layers which is the main place for hydrocarbon residue occurrence in microfacies type e without lamination microfacies g and h are both micrite microfacies g shows bioturbation and hydrocarbon residue occurs within small irregular microfractures along the bedding planes and pores only a little solid bitumen without fluorescence has been observed in microfacies h the rock eval oil saturation index osi s1 100 toc value is variable because of the different characteristics of these hydrocarbon residue occurrences osi values in microfacies a are normally high 74 8 242 8 mg hc g toc average of 117 2 mg hc g toc and likely much higher if microfractures develop 200 mg hc g toc osi values averaging 43 7 mg hc g toc are lowest in microfacies f because of adsorption on the shales and osi values are the highest in microfacies d 371 3 mg hc g toc and e 199 9 mg hc g toc since the hydrocarbon residues are stored both in microfractures and pores between the grains both osi values are high in microfacies g and h because of low toc content the combination of petrographic and osi analysis appear to be a promising tool for characterizing shale oil systems

comparative rock eval pyrolysis as an improved tool for sedimentary organic matter analysis an improved rock eval pyrolysis method is described for the global and exhaustive characterization of kerogen and bitumen in rock samples comparative pyrolysis is derived from the original rock eval method of espitalie et al it overcomes some of its inadequacies and allows a better exploitation of the pyrolysis data this new pyrolysis method is proposed mainly for routine analysis of bitumen in rock samples using a double analysis of each sample on whole rock and extracted rock the difference between these two pyrolysis curves corresponds to the bitumen pyrolysis curve and is used for estimating the total bitumen content the bitumen yield obtained in comparative pryolysis as a good correlation with the bitumen yield obtained by the standard solvent extraction method with however some limitations due to the mineral matrix effect the bitumen pyrolysis curve is further subdivided into three fractions which allow a quick and easy typing of bitumen products this method has been successfully applied to basin analysis

irregular recurrence of large earthquakes along the san andreas fault evidence from trees old trees growing along the san andreas fault near wrightwood california record in their annual ring width patterns the effects of a major earthquake in the fall or winter of 1812 to 1813 paleoseismic data and historical information indicate that this event was the san juan capistrano earthquake of 8 december 1812 with a magnitude of 7 5 the discovery that at least 12 kilometers of the mojave segment of the san andreas fault ruptured in 1812 only 44 years before the great january 1857 rupture demonstrates that intervals between large earthquakes on this part of the fault are highly variable this variability increases the uncertainty of forecasting destructive earthquakes on the basis of past behavior and accentuates the need for a more fundamental knowledge of san andreas fault dynamics

evidence of himalayan erosional event at 0 5 ma from a sediment core from the equatorial indian ocean in the vicinity of odp leg 116 sites abstract a sediment core collected from an area 100 miles south of the odp leg 116 distal bengal fan in the equatorial indian ocean was investigated for microfossils mineralogy mineral chemistry magnetic susceptibility grain size major minor and rare earth element geochemistry organic carbon and total nitrogen contents in the bulk sediments distinct changes in depositional characteristics including presence of abundant sand sized micas and other detrital minerals occur at two sub surface depths corresponding to 0 5 and probably 0 8 ma time periods the detrital mineral suite of this core resembles that of turbidite unit i sediments of odp cores in the distal bengal fan the core site has received an increased supply of terrigenous sediments at these two time periods the older pulse 0 8 ma stronger than the younger pulse several lines of evidence such as the nature of the mineral suite lower magnetic susceptibility values si al in mica mineral separates major element composition discrimination plots of ca ti versus k ti and k2o al2o3 and la yb ratios suggest a highly metamorphosed source such as higher himalayan crystalline hhc series indicating two events of increased physical weathering and erosion in the himalayan region while the erosional event of 0 8 ma is well known the episode of 0 5 ma was not reported earlier

application of biological markers in the assessment of paleoenvironments of chinese non marine sediments abstract in this study we employ molecular organic geochemical data for 22 representative sediment samples from chinese non marine sedimentary basins in an attempt to characterize and assess the non marine depositonal paleoenvironments the samples investigated include oilshale shale mudstone and sodium sulphate rich sediments ranging in age from cretaceous to tertiary it is evidenced by geological and geochemical data that those sediments studied originate from lacustrine environments ranging from freshwater brackish fresh water to hypersaline the aliphatic fractions of the sediment extracts were analyzed by gc and gc ms and relative abundance of compounds and compound classes of normal acyclic and cyclic alkanes were measured from mass chromatograms the results reveal significant differences in the chemical features of the various sample groups which enable them to be characterized and identified in terms of source and or environment related parameters the diagnostic parameters that allow this assessment are the relative abundances of n alkanes acyclic isoprenoid alkanes and 4 methyl steranes hopane sterane ratio gammacerane and homohopane indexes etc in this study data interpretation was also assisted by pattern recognition through principal component analysis the results show that the sample groups of different environmental origin could be unambiguously distinguished on scores plot

the influence of partial hydrocarbon saturation on porosity and permeability in a palaeogene lacustrine shale hosted oil system of the bohai bay basin eastern china abstract palaeogene calcareous 40 carbonate mudstones ro from 0 56 to 0 88 from the bohai bay basin were studied by combined petrographical geochemical and petrophysical analysis in order to assess and quantify the pore space pore filling and its influence on gas transport capacity toc contents ranged from 1 44 to 5 12 and porosities he determined by helium pycnometry from 1 3 to 6 4 bitumen filled porosity s1 was estimated to range between 0 3 and 2 0 based on rock eval s1 values and an assumed bitumen density of 0 90 g cm3 the true total porosity total he s1 amounts to 1 9 8 5 the in situ oil saturation so was estimated to range between 25 and 52 with two samples l69 1b and l69 2 having relatively high oil saturation 71 and 91 the conductivity of the remaining open pore space was measured on three samples with different orientations and oil saturations from 17 to 24 the effective klinkenberg corrected gas permeability coefficients range between 63 and 2000 ndarcy and permeability is highest parallel to bedding upon loading from 10 to 40 mpa confining pressure the intrinsic permeability coefficients decreased by one order of magnitude revealing a relatively high exponential stress sensitivity coefficient 0 069 mpa 1 and much lower zero stress permeability 1 416 10 6 md than most gas shales this could be due to pore plugging by ductile bitumen

experimental study of fluid transport processes in the matrix system of the european organic rich shales ii posidonia shale lower toarcian northern germany abstract a laboratory study has been conducted to investigate the transport of gases he ar ch 4 and water in the matrix of lower toarcian posidonia shale samples from three shallow boreholes in northern germany the maturity of the organic matter of the shale samples ranged between 0 53 and 1 45 vitrinite reflectance vr r the measurements were performed at effective stresses ranging between 6 and 37 mpa and a temperature of 45 c the effects of different controlling factors including permeating fluid maturity anisotropy moisture content and effective stress on the fluid conductivity were analyzed and discussed permeability coefficients measured perpendicular and parallel to bedding 3 10 22 to 9 7 10 17 m 2 were within the range previously reported for other shales and mudstones they exhibited a strong dependence on permeating fluid maturity anisotropy moisture content and effective stress the permeability coefficients measured with helium as permeate were consistently higher up to two times than those measured with argon and methane permeability coefficients measured with water were up to three orders of magnitude lower than klinkenberg corrected gas permeability coefficients measured with helium and methane under similar experimental conditions among the samples studied the lowest porosity and permeability coefficients were measured on samples of intermediate thermal maturity 0 88 vr r oil window permeability coefficients he ch 4 measured parallel to bedding were up to more than one order of magnitude higher than those measured perpendicular to bedding permeability coefficients measured with he and ch 4 on a dry sample were up to two times higher than those measured on a sample with the as received moisture content all samples showed a nonlinear reduction in permeability parallel to bedding with increasing effective stress 6 37 mpa the permeability anisotropy and stress dependence of permeability were controlled by the mineralogy

geochemistry of petroleum systems in the niuzhuang south slope of bohai bay basin part 3 estimating hydrocarbon expulsion from the shahejie formation abstract based on the distribution and geochemical characteristics of potential source rocks in the niuzhuang and guangbei sags and the niuzhuang south slope bohai bay basin the quantities of hydrocarbons expelled from the eocene oligocene shahejie formation were evaluated using a mass balance approach the results confirm that most of the hydrocarbons in the study area were generated and expelled from the shahejie formation source rocks in the niuzhuang sag the algae rich saline brackish water lacustrine es 4 oil shales of the shahejie formation from the bamianhe to wangjiagang region along the niuzhuang south slope exhibit excellent potential for early hydrocarbon generation but they are not the major source for proven oil reserves in the bamianhe region the source rocks for most of the known oil reserves in the study area occur in the es 4 mudstones in the deep part of the niuzhuang sag thus the commonly assumed origin of so called immature oils from source rocks shallower than the conventional oil window in this area needs revision

a 100 year average recurrence interval for the san andreas fault at wrightwood california evidence for five large earthquakes during the past five centuries along the san andreas fault zone 70 kilometers northeast of los angeles california indicates that the average recurrence interval and the temporal variability are significantly smaller than previously thought rapid sedimentation during the past 5000 years in a 150 meter wide structural depression has produced a greater than 21 meter thick sequence of debris flow and stream deposits interbedded with more than 50 datable peat layers fault scarps colluvial wedges fissure infills upward termination of ruptures and tilted and folded deposits above listric faults provide evidence for large earthquakes that occurred in a d 1857 1812 and about 1700 1610 and 1470

slip along the san andreas fault associated with the great 1857 earthquake historical records indicate that several meters of lateral slip along the san andreas fault accompanied the great 1857 earthquake in central and southern california these records together with dendrochronological evidence suggest that the rupture occurred along 360 to 400 km of the fault including several tens of kilometers of the currently creeping reach in central california geomorphic expressions of late holocene right lateral offsets are abundant along the 1857 rupture along 300 kilometers of the 1857 rupture between cholame and wrightwood the youngest discernible offset ranges from 3 to 9 1 2 meters dormancy of the fault since 1857 almost certainly indicates that this latest offset was created in 1857 fault slip apparently associated with the 1857 earthquake varies in a broadly systematic way along the trace of the fault it is relatively uniform along each of several long segments but changes rather abruptly in value between these segments this nonuniform displacement pattern may imply that some segments of the fault rupture more frequently or experience a slower long term slip rate than others the 1857 offsets indicate a seismic moment m o between 5 3 and 8 7 10 27 dyne cm assuming a 10 to 15 km depth of rupture and relatively uniform slip as a function of depth a comparison with the rupture length average slip value and tectonic setting of the california earthquake of 1906 m s 8 1 4 indicates a value of m 8 1 4 for the 1857 event

petroleum geology of the giant elm coulee field williston basin the elm coulee field of the williston basin is a giant oil discovery in the middle bakken formation devonian mississippian discovered in 2000 horizontal drilling began in the field in 2000 and to date more than 600 wells have been drilled the estimated ultimate recovery for the field is more than 200 million bbl of oil 31 8 million m3 the bakken formation in the field area consists of three members 1 upper shale 2 middle silty dolostone and 3 lower siltstone the total bakken interval ranges in thickness from 10 to 50 ft 3 1 to 15 3 m over the field area the upper shale is dark gray to black hard siliceous slightly calcareous pyritic and fissile the shale consists of dark organic kerogen minor clay silt size quartz and some calcite and dolomite the kerogen consists mainly of amorphous material and the organic material is distributed evenly throughout the shale interval not concentrated in laminations or lenses the upper shale ranges in thickness from 6 to 10 ft 1 8 to 3 1 m over the field area the middle member consists of a silty dolostone and ranges in thickness from 10 to 40 ft 3 1 to 12 2 m the lower member in the elm coulee field consists of brownish gray argillaceous organic rich siltstone burrowing and brachiopod fragments are common in the lower member this facies is equivalent to the lower bakken black shale facies on the northern side of the field and is interpreted to be an updip landward equivalent to the deeper water black shale facies the lower member ranges in thickness from 2 to 6 ft 0 61 to 1 8 m based on the abundance of fossil content and amount of burrowing the members of the bakken formation are interpreted to have been deposited under aerobic middle member common burrows and rare fossils dsyaerobic lower member common fossils and lesser amount of burrows and anaerobic conditions upper member rare fossils and burrows the main reservoir in elm coulee field is the middle member which has low matrix porosity and permeability and is found at depths of 8500 to 10 500 ft 2593 to 3203 m the current field limits cover approximately 450 mi2 1165 km2 the middle bakken porosities range from 3 to 9 and permeabilities average 0 04 md overall the reservoir quality in the middle bakken improves upward as the amount of clay matrix decreases the middle bakken is interpreted to be a dolomitized carbonate shoal deposit based on subsurface mapping and dolomite lithology the main production is interpreted to come from matrix permeability in the field area occasional vertical and horizontal fractures are noted in cores the vertical pay ranges in thickness from 8 to 14 ft 2 4 to 4 3 m the bakken is slightly overpressured with a pressure gradient of 0 53 psi ft 0 02 kpa m horizontal wells are drilled on 640 to 1280 ac 259 to 518 4 ha spacing units long single laterals dual laterals and trilaterals have all been drilled in the field the horizontal intervals are sand gel and water fracture stimulated initial production ranges from 200 to 1900 bopd 31 8 to 302 1 m3 day initial potential rates for vertical wells are generally less than 100 bopd 15 9 m3 day the upper bakken shale probably also contributes to the overall production in the field the exact contribution is unknown but estimated to be less than 20 of the total production the elm coulee field illustrates that the bakken petroleum system has enormous potential for future oil discoveries in the williston basin

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

fault fracture mesh petroleum plays in the jiyang superdepression of the bohai bay basin eastern china abstract based on the results of laboratory simulation experiments and field observations the concept of fault fracture mesh petroleum play is proposed to explain the secondary petroleum accumulations in the neogene reservoirs of the jiyang superdepression bohai bay basin eastern china a well defined fault fracture mesh petroleum play usually contains three basic elements an oil source network at the base a transient storage for migrating hydrocarbons in the middle and a petroleum accumulation network at the top the oil source network provides fairways for hydrocarbons generated in a deep source to migrate vertically upward to shallow strata often consisting of primary faults and fracture zones and or regional unconformities in direct contact with mature petroleum source beds and secondary faults intercepting lenticular fluvial sandstones the transient storages for migrating hydrocarbons include the thick porous mat or sheet like sandstones deposited under the fluvial braided stream setting and occurring over relatively large geographic areas these sandstones serve as temporary storage spaces through which deep sourced petroleum fluids migrate further either laterally or vertically into shallower reservoirs the upper petroleum accumulation network provides suitable habitats for oil and gas accumulation comprising structural lithologic stratigraphic and combination traps the jiyang superdepression of the bohai bay basin hosts several excellent examples of the fault fracture mesh petroleum play where hydrocarbons in the neogene reservoirs were derived either directly from eocene oligocene source rocks or from the redistribution of pre existing oil accumulations in the deeper reservoirs reactivation of basement involved faults and regional unconformities provided conduits for channeling the pre neogene hydrocarbons into the shallow strata the magnitudes and frequencies of the faulting activities and their relative timings to those of peak oil generation and expulsion were critical factors for controlling the quantities of hydrocarbons transmitted to the neogene strata the thick sandstones and conglomerates in the lower guantao formation acted as excellent transient storages for the deep sourced oils which were then trapped to form accumulations in the shallow structural lithologic stratigraphic and combination traps of the guantao ng minhuazhen nm formations with the recent discovery of several giant oilfields in the shallow neogene reservoirs both onshore and offshore bohai bay basin the proposed fault fracture mesh petroleum play concept helps the exploration geologists to modify and clarify long held traditional concepts of petroleum play types in this basin and expand upon the new exploration horizons of the shallow subtle petroleum traps

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

thermal maturation of gas shale systems shale gas systems serve as sources reservoirs and seals for unconventional natural gas accumulations these reservoirs bring numerous challenges to geologists and petroleum engineers in reservoir characterization most notably because of their heterogeneous character due to depositional and diagenetic processes but also because of their constituent rocks fine grained nature and small pore size much smaller than in conventional sandstone and carbonate reservoirs significant advances have recently been achieved in unraveling the gaseous hydrocarbon generation and retention processes that occur within these complex systems in addition cutting edge characterization technologies have allowed precise documentation of the spatial variability in chemistry and structure of thermally mature organic rich shales at the submicrometer scale revealing the presence of geochemical heterogeneities within overmature gas shale samples and notably the presence of nanoporous pyrobitumen such research advances will un

lateral offsets and revised dates of large prehistoric earthquakes at pallett creek southern california recent excavation and new radiocarbon dates of sediments at pallett creek are the basis for new conclusions regarding the late holocene history of the san andreas fault systematic dissection of a 50 m long 15 m wide 5 m deep volume of earth centered on the fault enables documentation in three dimensions of fault patterns lateral offsets and vertical deformation associated with large earthquakes of the past the excavations expose evidence for 12 earthquakes that occurred between about 260 and 1857 a d with an average recurrence interval of about 145 years prehistoric slip events that occurred in 1720 50 1550 70 1350 50 1080 65 and 845 75 a d have lateral offsets that are comparable to those of the most recent great earthquake of 1857 thus all of these events represent earthquakes of large magnitude the lateral offsets of two other events in 935 85 and 1015 100 a d are an order of magnitude smaller and may be interpreted in several ways with regard to the size of these events the new data constrain the average recurrence interval for large earthquakes at this site to between 145 and 200 years but suggest a monotonic decrease in individual intervals to below this range during the past 900 years on the basis of these data the probability of a large earthquake with surficial fault rupture at this site is between 0 2 and 5 during 1984 and 7 and 60 by the year 2000

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