evaluation of kinetic uncertainty in numerical models of petroleum generation oil prone marine petroleum source rocks contain type i or type ii kerogen having rock eval pyrolysis hydrogen indices greater than 600 or 300 600 mg hydrocarbon g total organic carbon hi mg hc g toc respectively samples from 29 marine source rocks worldwide that contain mainly type ii kerogen hi 230 786 mg hc g toc were subjected to open system programmed pyrolysis to determine the activation energy distributions for petroleum generation assuming a burial heating rate of 1c m y for each measured activation energy distribution the calculated average temperature for 50 fractional conversion of the kerogen in the samples to petroleum is approximately 136 7c but the range spans about 30c 121 151c fifty two outcrop samples of thermally immature jurassic oxford clay formation were collected from five locations in the united kingdom to determine the variations of kinetic response for one source rock unit the samples contain mainly type i or type ii kerogens hi 230 774 mg hc g toc at a heating rate of 1c m y the calculated temperatures for 50 fractional conversion of the oxford clay kerogens to petroleum differ by as much as 23c 127 150c the data indicate that kerogen type as defined by hydrogen index is not systematically linked to kinetic response and that default kinetics for the thermal decomposition of type i or type ii kerogen can introduce unacceptable errors into numerical simulations furthermore custom kinetics based on one or a few samples may be inadequate to account for variations in organofacies within a source rock we propose three methods to evaluate the uncertainty contributed by kerogen kinetics to numerical simulations 1 use the average kinetic distribution for multiple samples of source rock and the standard deviation for each activation energy in that distribution 2 use source rock kinetics determined at several locations to describe different parts of the study area and 3 use a weighted average method that combines kinetics for samples from different locations in the source rock unit by giving the activation energy distribution for each sample a weight proportional to its rock eval pyrolysis s2 yield hydrocarbons generated by pyrolytic degradation of organic matter

estimation of kerogen porosity in source rocks as a function of thermal transformation example from the mowry shale in the powder river basin of wyoming evaluations of porosity relevant to hydrocarbon storage capacity in kerogen rich mudrocks i e source rocks have thus far been plagued with ambiguity in large part because conventional core and petrophysical techniques were not designed for this rock type the growing recognition of an intraparticle organic nanopore system that is related to thermal maturity is beginning to clarify this ambiguity this mode of porosity likely evolved with the thermal transformation of labile kerogen and probably neither depends nor interacts except perhaps chemically with previously assumed matrix or mineral porosity that is dominated by bound water and that may be largely irrelevant to hydrocarbon storage capacity in these rocks to address this newly recognized and important nonmatrix kerogen pore system that is arguably the dominant hydrocarbon storage and mobility network in these rocks we introduce a relatively simple kinetic model that describes porosity development within kerogen as a function of thermal maturation kerogen porosity development is estimated within the upper albian mowry shale in the powder river basin of wyoming to illustrate the approach relevant storage capacity is considered to have evolved with thermal decomposition of organic matter during catagenesis where we estimate that kerogen porosity does not typically exceed 3 of bulk rock volume modeled oil in place estimates are comparable to residual oil estimates from pyrolysis data s1 at lower maturities but exceed pyrolytic s1 yields at higher maturities we hypothesize therefore that a subsurface kinetic porosity model might represent a means to account for s1 losses at surface conditions and to circumvent difficulties surrounding estimations of expulsion efficiencies that are inherent to more traditional mass balance calculations

eaglebine play of the southwestern east texas basin stratigraphic and depositional framework of the upper cretaceous cenomanian turonian woodbine and eagle ford groups the woodbine and eagle ford groups of the southwestern east texas basin compose an emerging play which has generated considerable interest because of its potential for new hydrocarbon production from both sandstone and mudrock reservoirs however the play s stratigraphic and depositional relations are complex and directly relate to the play s exploration challenges productive woodbine and eagle ford sub clarksville sandstones intertongue with a poorly defined subregional mudrock dominated interval that thins southwestward toward the san marcos arch we propose dividing this succession into two intervals 1 the lower unit a high gamma ray unit at the base of this mudrock succession that is inferred to be equivalent to the maness shale of the washita group and to part of the lower eagle ford group on the san marcos arch and 2 an upper unit a basinward thickening zone of consistently lower gamma ray log facies inferred to be equivalent to the woodbine group pepper shale and the eagle ford group of the east texas basin because the cenomanian turonian boundary occurs within the eagle ford group of the east texas basin and the lower eagle ford section of the san marcos arch most of the maness through eagle ford succession exists as a much thinned section on the arch basinwide integration of the woodbine sequence stratigraphic framework shows that the number of fourth order sequences in the unit decreases westward from 14 in the basin axis to no more than 9 in the most active part of the eaglebine play because of their systematic depositional pinch out approaching the western basin margin the eagle ford group consists of three fourth order sequences capped by the sub clarksville sandstones that accumulated after the major late cenomanian early turonian flooding event recorded by a basinwide transgressive systems tract tst at the base of the unit depositional systems of the woodbine group vary within the study area even between stratigraphically adjacent systems on shelf siliciclastic systems include fluvial dominated delta incised valley fill fluvial and nearshore marine and wave dominated delta deposits

formation of nanoporous pyrobitumen residues during maturation of the barnett shale fort worth basin abstract hydrocarbon generation reactions occur within organic rich shales as a response to thermal maturation here we report observations on samples from the organic rich mississippian barnett shale gas system fort worth basin texas usa at varying stages of thermal maturation a multiscale characterization was achieved using a combination of compositional organic geochemistry and spectromicroscopy techniques including synchrotron based scanning transmission x ray microscopy stxm and transmission electron microscopy tem we document the chemical evolution of the macromolecular structure of barnett shale kerogen with increasing maturity from an immature kerogen containing a significant aliphatic component and an important concentration of oxygen and sulfur containing functional groups to an overmature kerogen dominated by poorly condensed aromatic structures in addition to the presence of bitumen in samples of oil window maturity very likely genetically derived from thermally degraded kerogen the formation of nanoporous pyrobitumen has been inferred for samples of gas window maturity likely resulting from the formation of gaseous hydrocarbons by secondary cracking of bitumen compounds

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

geochemistry of the extremely high thermal maturity longmaxi shale gas southern sichuan basin abstract the marine shale of the silurian longmaxi formation in southern sichuan basin china is characterized by its huge thickness 100 600 m high toc values 0 35 18 4 favorable types of organic matter i and ii1 high ro values 1 8 4 2 abundant brittle minerals average 56 3 and strong gas generation intensity particularly its bottom section which has toc 2 and thickness of 20 70 m has recently been a main target for shale gas exploration and development geochemical parameters of 13 gas samples from longmaxi shale from 10 wells were analyzed in this study wetness of the gas molar fraction of ethane through pentanes in total gaseous hydrocarbon is only 0 24 0 70 making the longmaxi shale gas among the driest in the world carbon isotopic compositions of the alkane gases from longmaxi shale are characterized by 13c1 13c2 13c3 with the most positive 13c1 values in the world a positive relationship was observed between its 13c1 and 13c2 values reflecting the extremely high thermal maturity of the source rock 2hch4 values range from 140 to 151 and the 2hc2h6 values range from 130 to 173 the hydrogen isotopic compositions were mainly characterized by 2hch4

log derived thickness and porosity of the barnett shale fort worth basin texas implications for assessment of gas shale resources this study estimates reservoir quality and free gas storage capacity of the barnett shale in the main natural gas producing area of the fort worth basin by mapping log derived thickness porosity and porosity feet in the barnett shale the density porosity dphi log curve is a very useful tool to quantitatively assess shale gas resources and gamma ray gr and neutron porosity log curves are important factors in identifying the shale gas reservoir the key data were digital logs from 146 wells selected based on the availability of gr and density log curves log quality and good spatial distribution the barnett shale pay zone was determined on the basis of 1 dphi 5 2 high gr values commonly 90 api units 3 no significant intercalated carbonate rich beds and 4 individual pay zones being thick enough to be commercially successful for the current design of horizontal wells in the study area the barnett shale pay zone varies from about 165 ft 50 m to 420 ft 128 m in thickness h average dphi values of individual wells for the pay zone vary from 8 5 to 14 0 porosity feet maps of the pay zone show that areas of high dphi h values coincide with areas of high natural gas production indicating that log derived porosity feet maps are a good method for evaluating reservoir quality and assessing natural gas resource in the barnett shale play a limitation to this method is shown in the northwestern corner of the study area which is located in the liquids rich window with lower thermal maturity

the role of minerals in the thermal alteration of organic matter iii generation of bitumen in laboratory experiments abstract a series of pyrolysis experiments utilizing two different immature kerogens from the monterey and green river formations mixed with common sedimentary minerals calcite illite or namontmorillonite was conducted to study the impact of the mineral matrix on the bitumen that was generated calcite has no significant influence on the thermal evolution of bitumen and also shows virtually no adsorption capacity for any of the pyrolysate in contrast montmorillonite and illite to a lesser extent alter bitumen during dry pyrolysis montmorillonite and illite also display strong adsorption capacities for the polar constituents of bitumen by this process hydrocarbons are substantially concentrated within the pyrolysate that is not strongly adsorbed on the clay matrices the effects of the clay minerals are significantly reduced during hydrous pyrolysis the strong adsorption capacities of montmorillonite and illite as well as their thermocatalytic properties may in part explain why light oils and gases are generated from certain argillaceous source rock assemblages whereas heavy immature oils are often derived from carbonate source rocks

pore types and pore size distributions across thermal maturity eagle ford formation southern texas pore types pore size and pore abundance vary systematically across thermal maturity in the eagle ford formation maverick basin southern texas scanning electron imaging of 20 samples from four wells is used to assess the complex response of pores to chemical and mechanical processes entailing both destruction of primary porosity and generation of secondary pores primary mineral associated pores are destroyed by compaction cementation and infill of secondary organic matter whereas secondary pores are generated within organic matter om destruction of primary pores during early burial to 0 5 occurs by compaction of ductile detrital om and clays and to a lesser degree as a result of cementation and infill of secondary om larger pores are associated with coccolith debris the dominant om is spatially isolated detrital om stringers porosity is volumetrically dominated average 6 2 by relatively large mostly interparticle mineral associated pores median size 51 6 nm 0 000002 in detection limit near 3 4 nm 0 00000012 0 00000015 in at low maturity porosity and pore size correlate directly with calcite abundance and inversely with om volumes at higher maturity further destruction of primary pores occurs through cementation secondary om infill and greater compaction mineral associated pores are present at high maturity 1 2 1 3 but are smaller median size 30 2 nm 0 0000011 in and less abundant average of 2 5 than at low maturity a large portion of om within high maturity samples is diagenetic in origin and has pervaded into primary pore space coating cement crystals and filling intraparticle pores substantial mineral associated porosity is locally present in samples where incursion of primary pore space by secondary om has not occurred abundant secondary porosity is generated as om matures into the wet gas window porosity in most high maturity samples is volumetrically dominated average of 1 3 by smaller om hosted pores median size 13 2 nm 0 00000051 in

thermal maturity of the barnett shale determined from well log analysis intensive development with large scale fracturing treatments has made the barnett shale play newark east field in the fort worth basin the largest shale gas field in the world the mississippian barnett shale is an organic rich self sourced reservoir rock thermal maturity thickness and total organic carbon are the most important geological factors for commercial gas production from this shale formation the log derived thermal maturity index mi has been developed in an effort to better understand and predict hydrocarbon phases across the basin maturity index was calculated using three types of open hole logs neutron porosity deep resistivity and density porosity or bulk density the derivation of mi is based on the hypotheses that shale gas is generated and stored locally without apparent migration from outside sources and that the water saturation and the density of generated hydrocarbons decrease with an increase in thermal maturity maturity index correlates well with initial gas oil ratios gor from well production data based on this correlation an empirical relationship has been demonstrated for the fort worth basin this method is useful in understanding the thermal maturity levels of barnett shale source rock in the gas generation window mapping mi gor and gas heating value from hundreds of wells identifies the various maturity stages and areas of barnett shale that generate oil condensate wet gas or dry gas in the fort worth basin

carbon isotope fractionation during natural gas generation from kerogen abstract in petroleum exploration it is important to be able to determine the origin of any gas which is found this paper describes a new method of estimating the source type and maturity of a gas based on a rayleigh fractionation model kerogen is divided conceptually into a labile dominantly oil generating fraction and a refractory gas prone component 13 c of methane from either kerogen type and ethane propane and butane for gases from labile kerogen can be defined as a function of 13 c of the gas precursor groups in kerogen a kinetic isotope fractionation factor k and the extent of gas generation the isotopic ratio of the methane precursors relative to bulk kerogen determined from laboratory pyrolysis are 17 5 for labile kerogen and 1 4 for refractory kerogen values for ethane propane and butane from labile kerogen based on field correlations are 4 9 2 2 and 1 6 respectively the corresponding fractionation factors are 0 9892 0 9919 0 9947 and 0 9975 for methane ethane propane and butane respectively from labile kerogen and 0 9984 for methane from refractory kerogen using these parameters summary diagrams are constructed which allow differentiation of these sources from each other and from biogenic gases and cracked oil and recognition of gases of mixed origin if an independent estimate of 13 c for the source kerogen is possible then 13 c of the gas components can be used to estimate maturity in terms of the gas generation index the fraction of gas potential which has been realized

a comprehensive model of postseismic deformation of the 2004 sumatra andaman earthquake deduced from gps observations in northern sumatra abstract we investigate the postseismic deformation of the 2004 sumatra andaman earthquake sae using 5 years of global positioning system gps data located in northern sumatra continuous gps data from northern sumatra suggest that the relaxation time in the vertical displacement is longer than horizontal displacements this implies that there are multiple physical mechanisms that control the postseismic deformation which refer to afterslip and viscoelastic relaxation in this study we introduce an analysis strategy of postseismic deformation to simultaneously calculate multiple mechanisms of afterslip and viscoelastic relaxation the afterslip inversion results indicate that the distribution of the afterslip and the coseismic slip are compensatory of each other also afterslip has a limited contribution to vertical deformation in northern sumatra in our rheology model we use a gravitational maxwell viscoelastic response and the result indicates that the elastic layer thickness is 65 5 km and the maxwell viscosity is 8 0 1 0 1018 pa s we find that afterslip plus maxwell viscoelastic relaxation are appropriate to explain the deformation in northern sumatra we also find that our rheology model reproduces the long term features of the gps time series in thailand applying our rheology model to the data in andaman islands our afterslip estimation is located at the down dip part of the plate boundary finally we showed that our rheology model is applicable to the gps datasets of postseismic deformation of the 2004 sae located in northern sumatra thailand and andaman nicobar respectively

comparison of petroleum generation kinetics by isothermal hydrous and nonisothermal open system pyrolysis this study compares kinetic parameters determined by open system pyrolysis and hydrous pyrolysis using aliquots of source rocks containing different kerogen types kinetic parameters derived from these two pyrolysis methods not only differ in the conditions employed and products generated but also in the derivation of the kinetic parameters i e isothermal linear regression and non isothermal nonlinear regression results of this comparative study show that there is no correlation between kinetic parameters derived from hydrous pyrolysis and open system pyrolysis hydrous pyrolysis kinetic parameters determine narrow oil windows that occur over a wide range of temperatures and depths depending in part on the organic sulfur content of the original kerogen conversely open system kinetic parameters determine broad oil windows that show no significant differences with kerogen types or their organic sulfur contents comparisons of the kinetic parameters in a hypothetical thermal burial history 2 5 c my show open system kinetic parameters significantly underestimate the extent and timing of oil generation for type iis kerogen and significantly overestimate the extent and timing of petroleum formation for type i kerogen compared to hydrous pyrolysis kinetic parameters these hypothetical differences determined by the kinetic parameters are supported by natural thermal burial histories for the naokelekan source rock type iis kerogen in the zagros basin of iraq and for the green river formation type i kerogen in the uinta basin of utah differences in extent and timing of oil generation determined by open system pyrolysis and hydrous pyrolysis can be attributed to the former not adequately simulating natural oil generation conditions products and mechanisms

diamondoid hydrocarbon ratios novel maturity indices for highly mature crude oils abstract diamondoid hydrocarbons have been identified in oil and source rock samples from the tarim yinggehai qiongdongnan and other chinese basins two diamondoid hydrocarbon ratios have been used as novel high maturity indices to evaluate the maturation and evolution of crude oils and condensates in these chinese basins the two ratios 1 ma 1 ma 2 ma mai methyl adamantane index and 4 md 1 md 3 md 4 md mdi methyl diamantane index were found to increase with increasing vitrinite reflectance the initial values for the ratios are ca 50 and 30 respectively diamondoid hydrocarbons are products of rearrangement of polycyclic hydrocarbons and their ratios are found to be affected by organic input to a minor extent based on this study crude oils from the tarim basin are generally believed to be very mature ro 1 1 the cambrian ordovician source beds are the major source rocks of crude oils and natural gases in this basin condensates from the tarim yinggehai and qiongdongnan basins have higher maturities equivalent to ro values of 1 6 2 0 gases and condensates from the yinggehai and qiongdongnan basins are generated mainly from tertiary source rocks below 4000 5000 m

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

isotope reversals and universal stages and trends of gas maturation in sealed self contained petroleum systems abstract isotope geochemistry is now a tool for shale gas exploration largely due to the association of isotope reversals with mature highly productive shale gas its utility however depends on an understanding of the isotope systematics for the particular region of interest as well as for shale gas maturation in general this paper reviews and re examines isotope data from four published papers that include shale gas from the barnett and fayetteville shales rodrigez and philp 2010 zumberge et al 2012 and gas from fractured reservoirs in the appalachians burruss and laughrey 2010 and the foothills of the western canada sedimentary basin wcsb tilley et al 2011 new shale and tight sandstone gas data are also presented for the wcsb comparisons of these data show that the progression through three stages of gas maturation pre rollover zone rollover zone and post rollover zone is universal in sealed self contained petroleum systems and that each zone has characteristic isotopic relationships and trends that are seen in all areas examined gases in the pre rollover zone are isotopically normal 13 c methane 13 c ethane 13 c propane unless mixing of gases from different sources has occurred in the rollover zone 13 c ethane and 13 c propane become progressively more negative as 13 c methane becomes less negative and ethane and methane are reversed 13 c ethane 13 c methane only towards the most mature portion of the rollover zone at the beginning of the post rollover zone 13 c ethane 13 c methane but as 13 c ethane and 13 c propane become increasingly less negative at varying rates ethane and propane may or may not be reversed with respect to each other at the highest maturities 2 h methane in gases of the post rollover zone approaches isotopic equilibrium with local formation water generally becoming more negative with increasing maturity correct assignment of maturity stage could be of importance because the rollover zone may represent the peak of high productivity shale gas whereas the post rollover zone may represent a decline in productivity burruss and laughrey 2010

experimental simulation of primary migration abstract around fifty expulsion experiments were performed in a high pressure vessel specifically designed for the study of primary migration on natural source rock cores the results indicate that temperature pressure source rock richness and source rock architecture are the main parameters controlling the amount of petroleum expelled during the simulation in particular the control exerted by the pressure gradient and the source rock bulk permeability is well demonstrated another relevant result is the observation of the need for the production of a sufficient quantity of petroleum in the source rock before expulsion can start all these results have been compared with migration phenomena observed in the natural system and we discuss herein the similarities observed

organic matter maturation under the influence of a deep intrusive heat source a natural experiment for quantitation of hydrocarbon generation and expulsion from a petroleum source rock toarcian shale northern germany four shallow boreholes were drilled in the hils syncline northern germany in order to determine quantitatively the amount of hydrocarbons generated and expelled during maturation of a typical kerogen type ii bearing source rock the holes penetrated the carbonceous lias shales posidonia shale lower toarcian and part of the adjacent dogger and lias mudstones the maturity of the organic matter in the cores recovered ranges from immature 0 48 r0 to overmature 1 45 r0 due to location of the hils syncline in the vicinity of the vlotho massif which is deep seated intrusive body facies variations of the lias within the short geographical distances in the study area are negligible organic matter mass balance calculations were based on detailed organic geochemical analyses of residual material in the lias shales kerogen bitumen etc and on the evidence of a uniform initial composition of these sediments in the study area dead carbon determinations supported this latter criterion but were not used as a parameter in the calculations about 50 of the initial kerogen was transformed into oil gas and inorganic compounds during the vitrinite reflectance increase from 0 48 to 0 88 ro and only marginally more during the maturity increase from 0 88 to 1 45 ro only a small portion of the generated material remained in the source rock even at a relatively early stage of generation 0 68 ro expulsion efficiency of oil plus gas reached a value of 86 at the end of the main generation stage 0 88 ro

origins of partially reversed alkane δ13c values for biogenic gases in china with increasing molecular weight 13c values of hydrocarbon gases change in two different manners the normal order would be 13c1 13c2 13c3 13c4 partially reversed order is common in gas samples from sedimentary basins in china which can be attributed to one or several of the following four mixing processes a mixing of biogenic and abiogenic gases b mixing of sapropelic and humic sourced gases c mixing of gases from the same types of source rocks with different maturity and d mixing of gases from the same source rock interval of varying maturity

geochemical effects of primary migration of petroleum in kimmeridge source rocks from brae field area north sea i gross composition of c15 soluble organic matter and molecular composition of c15 saturated hydrocarbons in mature oil prone source rocks of the upper jurassic kimmeridge clay in the brae field area north sea the yield and the gross composition of solvent extractabte pctroleum likc compounds as well as the molecular proportions of c15 saturated hydrocarbons are primarily controlled by the effects of hydrocarbon expulsion during primary migration within sample series extending from shale centres towards adjacent reservoir sandstones regular and pronounced yield decreases have been documented as well as marked compositional changes for c15 soluble organic matter and its compound class fractions saturated hydrocarbons aromatic hydrocarbons nso compounds and for normal and isoprenoid alkanes relative migration losses indicating relative expulsion efficiencies were determined for the c15 alkanes throughout the outer five meters of thick shales relative expulsion efficiencies increase regularly and drastically for all compounds considered e g exceeding 90 for the c15 n alkanes in the outermost shale samples samples from thin 5 50 cm shale layers interbedded between reservoir sandstones reveal similarly high expulsion efficiencies for n alkanes the degree of depletion remains uniform throughout the molecular range c15 to c30i e no compositional fractionation occurred during primary migration which is interpreted to reflect expulsion of oil as a single phase fluid a simple conceptual model is proposed to explain the mechanisms and relationships of generation and expulsion processes in time and space a geochemically relevant conclusion is that the c15 soluble organic matter recovered by solvent extraction of mature source rocks represents only a portion of the total non volatile petroleum like material originally generated

understanding of hc migration in sedimentary basins present state of knowledge abstract great advances were made during the decade of 1975 1985 in the understanding of hc migration by establishing that the main mechanisms were polyphasic flow whatever its stage and that migration in solution in water and or by molecular diffusion was insignificant except for methane ethane and benzene research is now focusing on points which still have not been satisfactorily answered such as 1 1 behaviour of source rocks during hc expulsion the main driving force for fluid expulsion has been recognized to be excess fluid pressure within the source rock with respect to its surrounding environment of permeable beds the pressure build up is due mainly to accommodation by the fluids of part of the mechanical stresses which are exerted on the rock mainly sedimentary load but also stresses developed by tectonics to thermal expansion of water and to hc formation from kerogen in response to increasing temperatures however it is not clear whether or not petroleum expulsion proceeds preferentially along oil wet networks kerogen or oil wet mineral surfaces nor it is not clear whether or not microfracturing provoked by an internal fluid pressure higher than allowed by the mechanical strength of source rocks is necessary for hc expulsion 2 2 modifications of the compositions of hc phases e g oil versus gas or the distribution of biomarkers during migration and losses of hydrocarbons along the migration pathways although careful observations of natural sample series and also experimentation have been done no clear picture has emerged for the moment however compositional effects seem to be due more to changes in thermodynamic conditions along migration pathways which provoke inter alia hydrocarbon phase separation retrograde condensation than to differential retention by mineral surfaces it is likely that while careful observations on a large variety of source rock samples are needed to more clearly understand source rocks functioning progress in understanding hc migration will come increasingly from modeling and experimentation models which mathematically simulate natural processes are necessary to help the human mind in handling such complex phenomena and therefore are of precious help to focus research on the most important points they replace migration in its geological and historical dimensions with numerical or conceptual tools while observation only describes the present state models are also the tools by which knowledge on migration can be applied to exploration problems however quantitative applications of models require numerous and precise geological data that are difficult to gather at early stages of exploration in the field of experimentation it will be easier to design crucial experiments now that hc migration mechanisms are better understood thanks to experimentation it should also be possible to validate models however so as to reach such aims substantial progress has to be made in the technology of experimental systems

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

geochemical evolution of organic rich shales with increasing maturity a stxm and tem study of the posidonia shale lower toarcian northern germany hydrocarbon generation and retention processes occurring within gas shales as a response to increases in thermal maturation are still poorly constrained while efforts have been directed at unravelling the resource potential composition and textures of these economically important unconventional systems their spatial variability in chemistry and structure is still poorly documented at the sub micrometer scale here we have characterized samples of the lower toarcian posidonia shale samples from northern germany at varying stages of thermal maturation using a combination of compositional organic geochemistry and spectromicroscopy techniques including synchrotron based scanning transmission x ray microscopy stxm we document geochemical and mineralogical heterogeneities down to the nanometer scale within the investigated samples as a function of their level of thermal maturity in particular authigenic albite crystals containing nanometric halite inclusions have been documented within the investigated mature and overmature samples the presence of such tracers of palaeobrine carbonate interactions supports a maturation scenario for the lower toarcian posidonia shale intimately related to ascending brine fluids rather than a maturation scenario solely resulting from high heat flows in addition various types of asphaltene and nso rich bitumen have been detected within the same samples very likely genetically derived from thermally degraded organic precursors furthermore the formation of nanoporous pyrobitumen has been inferred for samples of gas window maturity likely resulting from the formation of gaseous hydrocarbons by providing in situ insights into the fate of bitumen and pyrobitumen as a response to the thermal evolution of the macromolecular structure of kerogen the results reported here constitute an important step towards better constraining hydrocarbon generation processes during natural shale gas maturation

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 formation fort worth basin texas bulk geochemical inferences and mo toc constraints on the severity of hydrographic restriction abstract chemostratigraphic evidence from the barnett formation texas usa elucidates the restricted nature of the depositional environment in the fort worth basin during the early progression of the late paleozoic ouachita orogeny in accord with recent lithostratigraphic and petrographic studies stratigraphic bulk geochemical analyses reveal that the environment of deposition was anoxic to euxinic sediment starved with relatively high rates of organic matter accumulation using an environmental proxy developed from the sediment geochemistry of modern anoxic silled basins the stratigraphic concentrations of total organic carbon toc and molybdenum mo in the barnett formation reveal a high degree of subpycnoclinal water mass restriction and an extended timescale of deep water renewal of at least 8 103 years and potentially as long as 2 104 years an integrated assessment of elemental concentrations the degree of pyritization and toc s fe relationships reveals that severe fe limitation controlled pyrite formation and the large excess of sulfide in the overlying water column mineralogical and elemental constraints suggest that following sulfate reduction less easily bio extractable fe iii was bio reduced under methanogenic conditions consequently liberating fe ii which was subsequently incorporated into pore water formed dolomite i e organogenic dolomite the preserved mo toc toc s fe and fe bearing mineral relationships collectively indicate that the protracted turnover rate and persistent sediment starvation resulted in a biologically inhospitable environment that limited the microbial consumption rate of organic carbon

correlation of natural gas by use of carbon isotopic distribution between hydrocarbon components the natural distribution of carbon isotopes between hydrocarbon gas components is used for 1 determining a gas s maturity 2 correlating a reservoired gas to its source 3 correlating one reservoired gas with another and 4 recognizing gas mixtures calculated separations of carbon isotopes between the normal alkane components of a natural gas have been related to source rock maturity by use of a single continuous diagram independent of source type actual data from a wide variety of geologic settings and geologic ages confirm this relationship and demonstrate its applicability to the source rock levels of organic metamorphism ranging from 8 to 13 covering the entire range of oil and wet gas generation at greater maturities the wet gas components are found to undergo thermal degradation losing their usefulness for correlation three examples showing indigenous gas west texas non indigenous gas gippsland basin australia and gas mixtures from multiple sources southeastern alberta illustrate exploration applications

microscopic and sedimentologic evidence for the generation and migration of hydrocarbons in toarcian source rocks of different maturities abstract this study is part of a comprehensive research program on the generation and migration of petroleum from the organic rich posidonia shale lower toarcian jurassic of the hils syncline northern germany four cores of the complete posidonia shale with varying amounts of underlying pliensbachian and overlying aalenian mudstones provided the sample base depending upon their distance from a presumed subjacent heat source the vlotho massif the cores display progressive levels of increasing thermal maturation with r 0 values 0 48 0 68 0 88 and 1 45 which span the limits of the oil generation window primary stratigraphic lithologic and petrographic attributes of the four sections are all very similar each includes a lower marlstone member about 5 m thick overlain by 11 31 m of calcareous clay shale clay minerals calcite pyrite kerogen and quartz are the principal constituents thus there is no evidence that depositional conditions of the posidonia shale varied significantly over the sampled area the omnipresence of framboidal pyrite clearly formed from the activity of sulphate reducing bacteria at or near the depositional interface is strong evidence that uniform reducing anoxic conditions were persistent at all localities this conclusion supports the assumption that initially each section was identical in overall properties and that significant differences observed in geochemistry organic macerals and other properties are directly related to the variable levels of thermal maturation kerogen from the least mature section r o 0 48 is type ii and composed of alginite a alginite b liptodetrinite bituminite and some terrestrial sporinite vitrinite and inertinite macerals with increasing maturation the alginite macerals exhibit a progressive change in morphology and fluorescence properties alginite of the least mature section displays a strong green fluorescence at 0 68 r o alginite macerals exhibit yellow orange fluorescence and are structurally well preserved although geochemical data indicate generation and loss of large amounts of oil at 0 88 r o hydrocarbon generation is almost complete and few primary alginites remain they have been transformed into secondary liptinites designated as metaalginite which have similar fluorescence colours at the highest maturation level 1 45 r o metaalginites are only weakly fluorescent with a shift toward red colours calcite and or bitumen filled bedding plane micro and macrofractures occur exclusively in the organic rich posidonia shale at maturity levels of 0 68 r o and above such features are totally absent in the immature posidonia section and in the adjacent organic poor mudstones this observation indicates that the fractures developed in direct response to overpressuring i e pore pressure exceeding lithologic load related to oil and gas generation in the source rock the fractures undoubtedly provided important expulsion conduits for generated products

atomic h c ratio of kerogen as an estimate of thermal maturity and organic matter conversion in recent years the atomic h c hydrogen to carbon ratio of kerogen as a way to assess the quality of organic matter in source rocks has been overlooked in favor of the more easily determined rock eval hydrogen index rock eval pyrolysis provides fast inexpensive quantitative mg hc g rock data without requiring kerogen isolation from the rock because of the general scatter in the data many source rock interpreters consider rock eval pyrolysis to be a screening analysis in this paper i describe the benefits of using h c ratios in source rock evaluations and present new correlations between atomic h c ratios and thermal maturity organic matter conversion and expulsion volumetrics atomic h c ratios of pyrolyzed kerogens have been correlated to the extent of thermal conversion of organic matter for both type i and type ii kerogens the excellent agreement between stoichiometric calculated hydrogen and carbon loss to observed losses from hydrous pyrolysis maturation experiments suggests that kerogen h c ratios are excellent indicators of thermal maturity for end member kerogen types these data also offer a method to estimate percent organic matter conversion provided that both the initial and present h c ratios of the kerogen are known present h c ratios can be measured and initial h c ratios can be reasonably estimated from microscopic organic analysis of kerogen for oil prone source rocks typical immature type i kerogens have h c ratios of 1 35 1 50 whereas type ii kerogens have h c ratios of 1 20 1 35 correlations of the amount of expelled oil in hydrous pyrolysis experiments to atomic h c ratio of the spent kerogen offer exploration geologists a quick estimate of oil expulsion volumes based on hydrous pyrolysis experiments measured h c ratios and calculated original toc total organic carbon values first order volumetric approximations were made on three basins containing mature source rocks results compared favorably with published approximate oil in place estimates for the williston basin bakken shale los angeles basin nodular shale and the illinois basin new albany shale

a preliminary study on the pore characterization of lower silurian black shales in the chuandong thrust fold belt southwestern china using low pressure n2 adsorption and fe sem methods although lower silurian black shales within and around the sichuan basin have received renewed attention during the past few years because of their potential prospectivity for shale gas studies associated with shale gas reservoir evaluation are still rare in this study eight black shale core samples were collected from a well drilled recently in the chuandong thrust fold belt southwestern china and their geochemistry and pore structures were investigated using low pressure n2 adsorption analysis and field emission scanning electron microscopy fe sem observations the results show that the black shales have total organic carbon toc values ranging from 1 01 to 3 98 and their equivalent vitrinite reflectance values are in the range of 2 84 3 05 both mineral matrix and organic matter pores are well developed with pore sizes ranging from several to several hundred nanometers the total porosity for the eight samples ranges from 2 60 to 4 74 and the percentages of organic matter pores are estimated to be in the range of 31 62 the total surface area ranges from 5 06 m2 g to 19 32 m2 g and the micropore 2 nm surface area estimated by the t plot method ranges from 3 13 m2 g to 9 27 m2 g the toc values have positive relationships with the total porosity total surface area and the micropore 2 nm volume and surface area indicating toc may be an effective parameter for shale gas reservoir evaluation in the studied area

genetic characterization of natural gases natural gases can be characterized genetically using four properties c2 concentration carbon and hydrogen isotope variations in methane and carbon isotope variation in ethane three diagrams for genetic characterization of gases have been designed in which the carbon isotopic composition of methane is correlated with the other parameters in these diagrams compositional fields have been defined for primary gases biogenic thermogenic associated and thermogenic nonassociated and for gases which result from mixing of these gases these fields are strictly empirical and comprise compositional variations found in about 500 natural gases the isotopic and compositional variations in natural gases can be described in terms of 1 processes during formation of the gases such as bacterial fermentation or maturation of organic matter and 2 processes during secondary migration mixing of primary gases is an important and common process migration of gases predominantly affects the c2 concentration whereas the isotopic properties of gaseous hydrocarbons primarily remain unchanged allowing an assessment of the origin of migrated gases and properties of their source rocks the formation of gas from humic organic matter and coals is not yet clear from published data the diagrams use data from various basins and areas interstitial gases from the gulf of california are entirely of bacterial origin traces of thermogenic gases are formed only in the vicinity of dolerite sills gases in the south german molasse basin and in the vienna basin are of bacterial mixed and thermogenic origins data from the north italian po basin provide examples for genetic characterization of migrated gases

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

mineralogical and chemical variability of mountain red brown mediterranean soils the purpose of the current study was to quantitatively explore the dynamics of clay pedogenesis in red brown soils of the terra rossa type and associated soils mainly rhodoxeralfs of the mediterranean region with respect to bedrock and dust composition and the impact of the vegetation translocated elements silicon and potassium fifteen non cultivated shallow and leached mountain pedons were sampled in israel along three transects that represent various rainfall ranges and bedrock lithologies bulk and clay fraction chemical and mineralogical compositions as well as grain size were determined quantitative relative analysis of clay minerals displayed a large variability that was largely affected by leaching leaching was dependent on rainfall amount and bedrock soil permeability in general if the better soils were drained and leached the higher were the amounts of both kaolinite and illitic phases soil clay assemblages lay between two mineralogical end members one with dominance of smectite and the second with high values of kaolinite and illitization parameters potassium and silicon were mobile in soils relative to aluminum but under high rainfall or certain vegetation translocation by vegetation reached a degree that promoted illite or smectite formation local combinations of rainfall bedrock soil permeability and vegetation translocation of potassium and silicon dictated a large variability in clays including illite formation within a restricted group of red brown mediterranean soils

evolution of petrophysical properties of oil shales during high temperature compaction tests implications for petroleum expulsion abstract the transport properties of permian to miocene oil shales torbanite posidonia messel himmetoglu and condor were studied using petrophysical and geochemical techniques the aims of this study were to assess permeability of oil shales evaluate the evolution of porosity specific surface area and intergranular permeability during high temperature compaction tests and to verify the suitability of intergranular permeability for petroleum expulsion measured permeability coefficients for two samples were 0 72 10 21 m for the eocene messel shale and 2 63 10 21 m for the lower jurassic posidonia shale from s germany respectively bet specific surface areas of the original samples ranged from 0 7 to 10 6 m g and decreased after compaction to values from 0 3 to 3 7 m g initial porosity values ranged from 7 6 to 20 1 for pre deformation and from 9 99 to 20 7 for post deformation samples porosity increased during the high temperature compaction experiments due to petroleum generation and expulsion permeability coefficients estimated using the kozeny carman equation varied from 6 97 10 24 m to 5 22 10 21 m for pre deformation and from 0 2 10 21 m to 4 8 10 21 m for post deformation samples reflecting the evolution of their porosity and bet specific surface areas measured and calculated permeability were similar for the messel shale whereas calculated permeability was two orders of magnitude lower for the posidonia shale from s germany petroleum expulsion efficiencies under the experimental conditions ranged from 38 6 for the torbanite to 96 2 for the posidonia shale from s germany they showed strong positive correlation with the petroleum generation index r 0 91 and poor correlations with porosity r 0 46 average pore throat diameters r 0 22 and compaction r 0 02 estimated minimum pore system saturations for petroleum expulsion during the experiments were 12 for the torbanite and 30 for the posidonia shale from n germany pore system saturation determines whether expulsion occurs mainly through matrix or fracture permeability for samples with saturation levels above 20 fracture permeability dominated during the experiments evidence based on the measured permeability coefficients expulsion flow rates consideration of capillary displacement during generation related pore invasion and the existence of transport porosity suggests that fracture permeability is the principal avenue of petroleum expulsion from source rocks this conclusion is supported by microscopic observations

isotopic reversals with respect to maturity trends due to mixing of primary and secondary products in source rocks abstract carbon isotopic composition 13 c reversals with respect to maturity trends have been reported for ethane and propane in barnett shale gas in the fort worth basin u s a this trend also exists in some conventional gas reservoirs such as in the ordos basin china and appalachian basin u s a fractionation during mass transport is unlikely to be a significant mechanism because its effect is minor under geological conditions it would have caused more obvious reversal for methane than for ethane and propane and mass transport can not account for the occurrence of the trend both inside and outside source rocks this paper demonstrates that the reversal may result from mixing of indigenous primary gas generated directly from kerogen and secondary gas generated from oil and condensate within source rocks and presents deconvolution results using end members derived from a kinetic isotope fractionation model the results including the wetness and mixing ratio of primary and secondary gases are consistent with geological conditions condensates may be the major precursor of the secondary gas in shale when the reversal occurs a complete trend of 13 c variations in methane and ethane with maturity is proposed that is based on the indigenous mixing mechanism

empirical relationship between gas composition and thermal maturity in eagle ford shale south texas organic rich and carbonate rich eagle ford shale is a self sourced oil and gas reservoir with little alteration of gas chemistry as might be affected by petroleum expulsion and migration as such it provides an ideal natural laboratory to quantify the compositional variation of gases generated from oil prone type ii kerogen during thermal maturation the chemical composition of the gas released from rock crushing was conducted and integrated with rock eval pyrolysis to define the empirical relationship between gas compositional parameters and thermal maturity in this study from 10 wells in the eagle ford shale in south texas we collected 74 core samples having a range of thermal maturity the measured maximum temperature tmax values of hydrocarbons generated in rock eval pyrolysis range from 427 c to 494 c 800 f to 921 f and the calculated equivalent vitrinite reflectance roe values range from 0 51 to 1 73 based on tmax values total organic carbon content ranges from 0 3 to 8 53 with an average of 3 12 standard deviation of 1 77 burial depth is from 2989 6 to 13 827 3 ft 911 2 to 4214 6 m our results showed that gas composition in the eagle ford shale is mainly controlled by thermal maturity and three stages of gas generation are identified based on the c1 and c2 concentrations of the gases released by rock crushing from eagle ford shale core samples the three stages of gas generation correspond to the following processes of organic matter conversion 1 kerogen and bitumen thermal cracking to crude oil 2 bitumen and heavy crude oil thermal cracking to light oil and 3 light oil cracking to gas methane rich gas and an abundance of branched butane and pentane are generated in light oil cracking to gas resulting in high c1 c2 c1 c2 c3 i c4 n c4 and i c5 n c5 ratios increased cracking of normal alkanes such as n butane and n pentane occurs in the light oil cracking to gas empirical equations between gas compositional parameters and thermal maturity tmax or roe are obtained for oil prone type ii the c1 c2 c1 c2 c1 c2 c3 and i c4 n c4 ratios are the five best parameters for determining thermal maturity with an exponentially derived r2 value of 0 74 the composition of gas produced from the eagle ford shale following hydraulic fracturing is used to validate the empirical equations calculated thermal regime for the oil production based on the produced gas is located at the peak of oil generation and the beginning of light oil cracking to gas corresponding to tmax from 454 c to 464 c 849 f to 867 f or at an roe ranging from 1 01 to 1 19 empirical equations provide a basis for interpretation of mud gas logging data and produced gas composition

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

calculation of petroleum masses generated and expelled from source rocks abstract an algebraic scheme for calculating the masses of petroleum formed in mature source rocks has been constructed the scheme exploits routine geochemical measurements and a basic understanding of the behaviour of sedimentary organic matter at elevated temperatures under both laboratory and subsurface conditions application of these techniques to data from a wide range of source rock types has led to the following general conclusions 1 1 major oil and gas generation from kerogen occurs between 120 and 150 c in the subsurface gas generation continues to temperatures 160 c 2 2 oil prone source rocks with average initial potential 5 kgt 1 of rock and average organic carbon contents 1 5 expel 60 90 of the total oil generated 3 3 oil expulsion from leaner source rocks is less efficient most of the oil generated remains in the source rock it is subsequently converted to lighter components at higher temperatures and expelled in the vapour state 4 4 the major loss of organic carbon from rich oil prone source rocks during generation and expulsion means that the petroleum potential and organic carbon content of mature source rocks are much less than their initial immature values hence the algebraic scheme must be used to calculate the initial values before expelled petroleum masses can be determined