Thermal maturity evaluation using Raman spectroscopy for oil shale samples of USA:comparisons with vitrinite reflectance and pyrolysis methods

Thermal maturity is commonly assessed by various geochemical screening methods(e.g.,pyrolysis and organic petrology).In this contribution,we attempt to establish an alternative approach to estimating thermal maturity with Raman spectroscopy,using 24 North American oil shale samples with thermal maturity data generated by vitrinite reflectance(VRo%)and pyrolysis(Tmax)-based maturity calculation(VRe%).The representative shale samples are from the Haynesville(East Texas),Woodford(West Texas),Eagle Ford and Pearsall(South Texas)Formations,as well as Gothic,Mancos,and Niobrara Formation shales(all from Colorado).The Raman spectra of disordered carbonaceous matter(D1 and G bands separation)of these samples were directly obtained from the rock chips without prior sample preparation.Using the Gaussian and Lorentzian distribution approach,thermal maturities from VR were correlated with carbon G and D1.We found that the Raman band separation(RBS)displayed a better correlation for equivalent VRe%than vitrinite reflectance VRo%.The RBS(D1–G)distance versus total organic carbon,free hydrocarbons from thermal extraction(S1),and the remaining hydrocarbon generating potential(S2)indicate that the RBS(D1–G)distance is also related to kerogen type.Data presented here from three methods of maturity determination of shale demonstrate that Raman spectroscopy is a quick and valid approach to thermal maturity assessment.

Geochemical assessment of upper Cretaceous crude oils from the Iranian part of the Persian Gulf Basin:Implications for thermal maturity,potential source rocks,and depositional setting

The Upper Cretaceous carbonate successions of the Sarvak Formation host giant oil reservoirs in the Persian Gulf.In this research,a total of 28 oil samples from nine oilfields located in the western,central and eastern parts of the Persian Gulf region were studied to determine the genetic relationships of oils,depositional setting of possible source rocks,thermal maturity,and source-rock ages in the Persian Gulf basin.According to the measured geochemical data,the source rocks facies vary from marine carbonates and marl/carbonates in the central and eastern oilfields to shale/carbonates in the western oilfields.The Pr/Ph ratio,steranes and terpanes suggest anoxic to dysoxic conditions of the depositional environments.The depositional environments experienced both low water stratification/low salinity and normal salinity/unstratified conditions.Evaluation of the saturated and aromatic biomarkers shows that all oil samples are mature and most of the source rocks lie within the beginning of the oil-generation window.The thermal maturity of the central oilfields is higher than that of the other samples,and has gone beyond the oil-generation stage.The C2s/C2g steranes ratio suggest that the central oilfelds of the Persian Gulf have Paleozoic and Jurassic source rocks,whereas the Sarvak reservoir in other parts of this region is sourced from Cretaceous carbonate rocks.

Characterization of Organic-Rich Shales for Petroleum Exploration & Exploitation: A Review-Part 2: Geochemistry, Thermal Maturity, Isotopes and Biomarkers

As shale exploitation is still in its infancy outside North America much research effort is being channelled into various aspects of geochemical characterization of shales to identify the most prospective basins, formations and map their petroleum generation capabilities across local, regional and basin-wide scales. The measurement of total organic carbon, distinguishing and categorizing the kerogen types in terms oil-prone versus gas-prone, and using vitrinite reflectance and Rock-Eval data to estimate thermal maturity are standard practice in the industry and applied to samples from most wellbores drilled. It is the trends of stable isotopes ratios, particularly those of carbon, the wetness ra- tio （C1/~＇（C2＋C3））, and certain chemical biomarkers that have proved to be most informative about the status of shales as a petroleum system. These data make it possible to identify production ＂sweet- spots＂, discriminate oil-, gas-liquid- and gas-prone shales from kerogen compositions and thermal ma- turities. Rollovers and reversals of ethane and propane carbon isotope ratios are particularly indica- tive of high thermal maturity exposure of an organic-rich shale. Comparisons of hopane, strerane and terpane biomarkers with vitrinite reflectance （Ro） measurements of thermal maturity highlight dis- crepancies suggesting that Ro is not always a reliable indicator of thermal maturity. Major and trace element inorganic geochemistry data and ratios provides useful information regarding provenance, paleoenvironments, and stratigraphic-layer discrimination. This review considers the data measure- ment, analysis and interpretation of techniques associated with kerogen typing, thermal maturity, sta- ble and non-stable isotopic ratios for rocks and gases derived from them, production sweet-spot identi- fication, geochemical biomarkers and inorganic chemical indicators. It also highlights uncertainties and discrepancies observed in their practical application, and the numerous outstanding questions as- sociated with them.

Re-Establishing the Merits of Thermal Maturity and Petroleum Generation Multi-Dimensional Modeling with an Arrhenius Equation Using a Single Activation Energy

Thermal maturation and petroleum generation modeling of shales is essential for suc- cessful exploration and exploitation of conventional and unconventional oil and gas plays. For basin- wide unconventional resource plays such modeling, when well calibrated with direct maturity meas- urements from wells, can characterize and locate production sweet spots for oil, wet gas and dry gas. The transformation of kerogen to petroleum is associated with many chemical reactions, but models typically focus on first-order reactions with rates determined by the Arrhenius Equation. A miscon- ception has been perpetuated for many years that accurate thermal maturity modeling of vitrinite re- flectance using the Arrhenius Equation and a single activation energy, to derive a time-temperature index （~TTIARa）, as proposed by Wood （1988）, is flawed. This claim was initially made by Sweeney and Burnham （1990） in promoting their ＂EasyRo＂ method, and repeated by others. This paper dem- onstrates through detailed multi-dimensional burial and thermal modeling and direct comparison of the ~TTIARR and ＂EasyRo＂ methods that this is not the case. The ~TTIA^R method not only provides a very useful and sensitive maturity index, it can reproduce the calculated vitrinite reflectance values derived from models based on multiple activation energies （e.g., ＂EasyRo＂）. Through simple expres- sions the ~TTIAaa method can also provide oil and gas transformation factors that can be flexibly scaled and calibrated to match the oil, wet gas and dry gas generation windows. This is achieved in a more-computationally-efficient, flexible and transparent way by the ~TTIARR method than the ＂EasyRo＂ method. Analysis indicates that the ＂EasyRo＂ method, using twenty activation energies and a constant frequency factor, generates reaction rates and transformation factors that do not realisti- cally model observed kerogen behaviour and transformation factors over geologic time scales.

Thermal maturity and burial history modelling of shale is enhanced by use of Arrhenius time-temperature index and memetic optimizer

Thermal maturity indices and modelling based on Arrhenius-equation reaction kinetics have played an important role in oil and gas exploration and provided petroleum generation insight for many kerogenrich source rocks.Debate continues concerning how best to integrate the Arrhenius equation and which activation energies(E)and frequency factors(A)values to apply.A case is made for the strong theoretical basis and practical advantages of the time-temperature index(∑TTIARR)method,first published in 1998,using a single,carefully selected E-A set(E?218 kJ/mol(52.1 kcal/mol);A?5.45Et26/my)from the well-established A-E trend for published kerogen kinetics.An updated correlation between ∑TTIARR and vitrinite reflectance(Ro)is provided in which the P TTIARR scale spans some 18 orders of magnitude.The method is readily calculated in spreadsheets and can be further enhanced by visual basic for application code to provide optimization.Optimization is useful for identifying possible geothermal gradients and erosion intervals covering multiple burial intervals that can match calculated thermal maturities with measured Ro data.A memetic optimizer with firefly and dynamic local search memes is described that flexibly conducts exploration and exploitation of the feasible,multi-dimensional,thermal history solution space to find high-performing solutions to complex burial and thermal histories.A complex deep burial history example,with several periods of uplift and erosion and fluctuating heat flow is used to demonstrate what can be achieved with the memetic optimizer.By carefully layering in constraints to the models specific insights to episodes in their thermal history can be exposed,leading to better characterization of the timing of petroleum generation.The objective function found to be most effective for this type of optimization is the mean square error(MSE)of multiple burial intervals for the difference between calculated and measure Ro.The sensitively-scaled P TTIARR methodology,coupled with the memetic optimizer,is well suited for rapidly conducting basin-wide thermal maturity modelling involving multiple pseudo-wells to provide thermal maturity analysis at fine degrees of granularity.

Geochemical fingerprints and hydrocarbon potential of Paleocene mudrocks in the Tano Basin, Ghana: insights from biomarkers and stable carbon isotopes

The Paleocene mudrocks in Ghana’s Tano Basin have received limited attention despite ongoing efforts to explore hydrocarbon resources.A thorough geochemical analysis is imperative to assess these mudrocks’petroleum generation potential and formulate effective exploration strategies.In this study,a comprehensive geochemical analysis was carried out on ten Paleocene rock cuttings extracted from TP-1,a discovery well within the Tano Basin.Various analytical techniques,including total organic carbon(TOC)analysis,Rock–Eval pyrolysis,gas chromatography-mass spectrometry,and isotope ratio-mass spectrometry,were employed to elucidate their hydrocar-bon potential and organic facies.Thefindings in this study were subsequently compared to existing geochemical data on Paleocene source rocks in the South Atlantic marginal basins.The results indicated that the Paleocene samples have TOC content ranging from 0.68 to 2.93 wt%.The prevalent kerogen types identified in these samples were Type Ⅱ and Type Ⅲ.Molecular and isotope data suggest that the organic matter found in the Paleocene mudrocks can be traced back to land plants and lower aquatic organisms.These mudrocks were deposited in a transi-tional environment withfluctuating water salinity,charac-terized by sub-oxic redox conditions.Maturity indices,both bulk and molecular,indicated a spectrum of maturity levels within the Paleocene mudrocks,spanning from immature to marginally mature,with increasing maturity observed with greater depth.In comparison,the organic composition and depositional environments of Paleocene source rocks in the Tano Basin closely resemble those found in the Niger Delta Basin,Douala,and Kribi-Campo Basins,the Kwanza Formation in Angola,and certain Brazilian marginal basins.However,it is worth noting that Paleocene source rocks in some of the basins,such as the Niger Delta and Brazilian marginal basins,exhibit rela-tively higher thermal maturity levels compared to those observed in the current Paleocene samples from the Tano Basin.In conclusion,the comprehensive geochemical analysis of Paleocene mudrocks within Ghana’s Tano Basin has unveiled their marginal hydrocarbon generation potential.The shared geochemical characteristics between the Paleocene mudrocks in the Tano Basin and those in the nearby South Atlantic marginal basins offer valuable insights into source rock quality,which is crucial for shaping future strategies in petroleum exploration in this region.

Distribution of sterane maturity parameters in a lacustrine basin and their control factors:A case study from the Dongying Sag,East China

Fifty samples from the source rocks in Member 3 and Member 4 of the Paleogene Shahejie Formation in the Bohai Bay Basin, East China, were analyzed to investigate the distribution, evolution of the molecular maturity ratios C29ββ/（ββ＋αα） and C2920S/（20S＋20R） and their control factors in the natural geological profile and sequence. The results showed that progressive changes in molecular maturity parameters are associated with major changes in thermal evolution of related biomarkers. Increases in the C29ββ/（ββ＋αα） and C2920S/（20S＋20R） ratios result from the difference in the relative rate between generation and thermal degradation of isomers involved. The samples from a hyper-saline environment below 3.5 km in which evaporitic rocks deposited shows high response of Sr/Ba, Sr/Ca, Fe/ Mn, Pr/n-C17, Ph/n-C18 and gammacerane and low response of Pr/Ph. There presents negative reversal of biomarker maturity C29ββ/（ββ＋αα, C29ββ/（ββ＋αα） and Ts/（Ts＋Ym） in the samples from hypersaline environment, reflecting that the gypsum- halite have negative effect on the isomerization of biomarker and thermal evolution of organic matter. The minerals in evaporites also retard the conventional thermal indicators including vitrinite reflectance （Ro） and pyrolysis peak temperature Tmax at the depth below 3.4 km （i.e. 〉3.4 km）, and these parameters also show the inhibition from overpressure in the range of 2.4-3.4 kin. This result will be helpful in the interpretation and application of molecular maturity parameters for similar saline lacustrine basins.

Hydrocarbon generation from lacustrine shales with retained oil during thermal maturation

Thermal maturation in the shale oil/gas system is inherently complex due to the competitive interplays between hydrocarbon generation and retention processes.To study hydrocarbon generation characteristics from shales within different stages of thermal maturation under the influence of retained oil,we performed Micro-Scale Sealed Vessels(MSSV)pyrolysis on a set of artificially matured lacustrine shale s amples from the Shahejie Formation in the Dongpu Depression in Bohai B ay Basin,China.Experimental results show that hydrocarbon yields of shale samples with or without retained oil at various thermal maturities follow different evolution paths.Heavy components(C15+)in samples crack at high temperatures and generally follow a sequence,where they first transform into C6-14 then to C2-5 and C1.Methane accounts for most of the gaseous products at high temperatures in all samples,with different origins.The cracking of C2-5 is the main methane-generating process in samples with retained oil,whereas the source of methane in samples without retained oil is kerogen.In the studied shales,retained oils at early-mature stage retard the transformation of liquid to gaseous hydrocarbon and prompt the cracking of C2-5 to C1 to some extent.TSR reaction related to gypsum in the studied samples is the primary reason that can explain the loss of hydrocarbon yields,especially at high temperatures.In addition,transformation of volatile hydrocarbons to gas and coke also accounts for the loss of generated hydrocarbon,as a secondary factor.

Source rock geochemistry of central and northwestern Niger Delta: Inference from aromatic hydrocarbons content

The influence of origin, depositional environment and thermal maturity of organic matter on the occurrence of aromatic hydrocarbons in source rocks from the central and northwestern Niger Delta was investigated. Eighty two source rock samples from four oil wells in the central and northwestern Niger Delta were analyzed for the aromatic hydrocarbon content using gas chromatography-mass spectrometry (GC-MS). The results of analysis of aromatic hydrocarbon fractions of the source rock extracts show the presence of many classes of aromatic hydrocarbons, which include naphthalenes, phenanthrenes, biphenyls, dibenzothiophenes and fluorenes. Trimethylnaphthalene (TMN) is the most abundant among the naphthalenes while dimethylphenanthrene (DMP) is the most abundant among the phenanthrenes. Among the biphenyls, 3-methylbiphenyl (3 MB) is the most abundant while 4-methyldibenzothiophene (4MDBT) is the most abundant among the dibenzothiphenes. Only two fluorenes were detected, and fluorene is more in abundance than 1-methylfluorene (1 MF). Depositional environment indicators of aromatic hydrocarbon organic matter reveal that the organic materials in the source rocks in these wells were deposited in marine-to-swamp depositional environments under reducing to suboxic conditions. Thermal maturity indicators calculated from the abundance of the aromatic hydrocarbons indicate that the source rock samples are thermally mature. Most of the source rocks are at the peak of oil window while a few at the early oil window. Source rocks from wells GB, OP and OT in the central Niger Delta are thermally more mature than those from well AW in the northwestern Niger Delta.

Estimation of the Shale Oil/Gas Potential of a Paleocene–Eocene Succession: A Case Study from the Meyal Area, Potwar Basin, Pakistan

The successful exploration and production of shale-gas resources in the United States and Canada sets a new possible solution towards the energy crisis presently affecting most countries of Asia. This study focuses on the use of well log and 2D seismic data for the characterization of the shale oil/gas potential of a Paleocene-Eocene succession -- the Meyal area in the Potwar Basin of Pakistan. Two shaly plays are identified in Paleocene-Eocene strata in well logs using ALogR and modified ALogR cross-plot techniques. The results indicate that Paleocene shale （the Patala Formation） and the lower shaly part of Eocene limestone （Sakesar Formation） can be potentially mature source rocks. However, the thermal maturity modelling proves that only the Paleocene shale is mature. Our results also suggest that the maturity responses on ALogR models for the lower shaly part of the Eocene limestone are due to trapped hydrocarbons in the intra-formational fractures. Petroelastic/petrophysical analysis of the Patala Formation reveals two potential shale oil/gas zones on the basis of Young＇s modulus, Poisson＇s ratio, Brittleness index and Total Organic Content at an exploitation depth of 3980-3988 m. This work can provide valuable insight for estimating shale oil/gas potential in highly deformed basins not only in Asia but in other parts of the world.

Origin of the Gas Hydrate and Free Gas in the Qilian Permafrost,Northwest China:Evidence from Molecular Composition and Carbon Isotopes

The Qilian permafrost of the South Qilian Basin(SQB)has become a research focus since gas hydrates were discovered in 2009.Although many works from different perspectives have been conducted in this area,the origin of gas from gas hydrate is still controversial.Molecular composition and carbon isotope of 190 samples related to gas hydrates collected from 11 boreholes allowed exploration of genetic type,thermal maturity,biodegradation,as well as gas-source correlation of alkane gases from gas hydrates and free gases.Results indicate that alkane gases biodegraded after the formation of natural gas.According to differences in carbon isotopes of methane and their congeners(CH4,C2H6,C3H8),the thermal maturity(vitrinite reflectance,VRo)of most alkane gases ranges from 0.6%to 1.5%,indicating a mature to high mature stage.The thermal maturity VRo of a small part of alkane gas(in boreholes DK5 and DK6)is higher than 1.3%,indicating a high mature stage.Alkane gases were mainly produced by secondary cracking,consisting of crude oilcracking gases and wet gases cracking to dry gases.Genetic types of alkane gases are primarily oil-type gases generated from shales and mudstones in the upper Yaojie Formation of Jurassic,with less coal-type gases originated from the mudstones in the Triassic Galedesi Formation and the lower Yaojie Formation of Jurassic.Carbon dioxides associated with alkanes from gas hydrates and free gases indicate the thermal decomposition and biodegradation of organic matter.The origins of natural gases from gas hydrates and free gases shed light on the evaluation of petroleum resource potential,deeply buried sediments,and petroleum resource exploration in the SQB.

Geochemical Evaluation of the Permian Ecca Shale in Eastern Cape Province, South Africa:Implications for Shale Gas Potential

Shale gas has been the exploration focus for future energy supply in South Africa in recent time. Specifically, the Permian black shales of the Prince Albert, Whitehill, Collingham, Ripon and Fort Brown Formations are considered to be most prospective rocks for shale gas exploration. In this study,outcrop and core samples from the Ecca Group were analyzed to assess their total organic carbon(TOC), organic matter type, thermal maturity and hydrocarbon generation potential. These rocks have TOC ranging from 0.11 to 7.35 wt%. The genetic potential values vary from 0.09 to 0.53 mg HC/g,suggesting poor hydrocarbon generative potential. Most of the samples have Hydrogen Index(HI) values of less than 50 mg HC/g TOC, thus suggesting Type-Ⅳ kerogen. Tmax values range from 318℃ to601℃, perhaps indicating immature to over-maturity of the samples. The vitrinite reflectance values range from 2.22% to 3.93%, indicating over-maturity of samples. Binary plots of HI against Oxygen Index(OI), and HI versus Tmax show that the shales are of Type II and mixed Type Ⅱ-Ⅲ kerogen.Based on the geochemical data, the potential source rocks are inferred as immature to over-matured and having present-day potential to produce gas.

Geochemical record for the depositional condition and petroleum potential of the Late Cretaceous Mamu Formation in the western flank of Anambra Basin, Nigeria

Carbonaceous shale exposures of the Late Cretaceous Mamu Formation along Ifon-Uzebba road in western arm(Benin Flank) of Anambra Basin, southwestern Nigeria, were analyzed for bulk organic geochemical, molecular biological and poly-aromatic hydrocarbon(PAH) compositions to investigate the organic matter source, paleo-depositional condition, thermal maturity and petroleum potential of the unit. The bulk organic geochemistry was determined using Leco and Rock-Eval pyrolysis analyses while the biomarkers and PAH compositions were investigated using gas chromatography-mass spectrometer(GC-MS).The bulk organic geochemical parameters of the shale samples showed total organic carbon(TOC)(1.11-6.03 wt%), S2(0.49-11.73 mg HC/g Rock), HI(38-242 mg HC/g TOC) and Tmax(425-435 C) indicating good to excellent hydrocarbon source-rock. Typical HI-Tmax diagram revealed the shale samples mostly in the gas-prone Type Ⅲ kerogen region with few gas and oil-prone Type Ⅱ-Ⅲ kerogen. The investigated biomarkers(n-alkane, isoprenoid, terpane, hopane, sterane) and PAH(alkylnaphthalene, methylphenanthrene and dibenzothiophene) indicated that the carbonaceous shales contain mix contributions of terrestrial and marine organic matter inputs that were deposited in a deltaic to shallow marine settings and preserved under relatively anoxic to suboxic conditions.Thermal maturity parameters computed from Rock-Eval pyrolysis, biomarkers(hopane, sterane) and PAH(alkylnaphthalene, alkylphenanthrene, alkyldibenzothiophene) suggested that these carbonaceous shales in Anambra Basin have entered an early-mature stage for hydrocarbon generation. This is also supported by fluoranthene/pyrene(0.27-1.12), fluoranthene/(fluoranthene + pyrene)(0.21-0.53) ratios and calculated vitrinite reflectance values(0.49-0.63% Ro) indicative that these shales have mostly reached early oil window maturity, thereby having low hydrocarbon source potential.

Pore structure evolution of lacustrine organic-rich shale from the second member of the Kongdian formation in the Cangdong Sag,Bohai Bay Basin,China

Pyrolysis experiments were conducted on lacustrine organic-rich shale from Cangdong Sag in Bohai Bay Basin,China,to investigate the impact of hydrocarbon generation on shale pore structure evolution.Thermal evolution is found to control the transformation of organic matter,hydrocarbon products characteristics,and pore structure changes.Furthermore,pore volume and specific surface area increase with increasing maturity.In low-mature stage,the retained oil content begins to increase,pore volumes show slight changes,and primary pores are occluded by the generated crude oil of high molecular weight and density.In the oil-window stage,the retained oil content rapidly increases and reaches maximum,and pore volumes gradually increase with increasing thermal maturity.At high mature stage,the retained oil content begins to decrease,and the pore volume increases considerably owing to the expulsion of liquid hydrocarbon.In over mature stage,natural gas content significantly increases and kerogen transforms to asphalt.Numerous organic pores are formed and the pore size gradually increases,resulting from the connection of organic pores caused the increasing thermal stress.This study lays a foundation for understanding variation of hydrocarbon products during the thermal evolution of lacustrine shales and its relationship with the evolution of shale reservoirs.

Deep resistivity "turnover" effect at oil generation "peak" in the Woodford Shale,Anadarko Basin,USA

The Devonian Woodford Shale in the Anadarko Basin is a highly organic,hydrocarbon source rock.Accurate values of vitrinite reflectance(R_o)present in the Woodford Shale penetrated by 52 control wells were measured directly.These vitrinite reflectance values,when plotted against borehole resistivity for the middle member of the Woodford Shale in the wells,display a rarely reported finding that deep resistivity readings decrease as R_o increases when R_o is greater than 0.90%.This phenomenon may be attributed to that aromatic and resin compounds containing conjugated pi bonds generated within source rocks are more electrically conductive than aliphatic compounds.And aromatic and resin fractions were generated more than aliphatic fraction when source rock maturity further increases beyond oil peak.The finding of the relationship between deep resistivity and R_o may re-investigate the previously found linear relationship between source rock formation and aid to unconventional play exploration.

Organic geochemistry and source rock potential assessment of Late Paleocene Patala Formation in Margalla Hill Range,North Pakistan

Black shales of the Paleocene Patala Formation are proven source rocks for conventional hydrocarbons in southern Potwar Basin of Pakistan and are assumed to be effective source rocks towards north in the Margalla Hill Range of Pakistan.In this regard,the current study focuses on source rock geochemistry of the Paleocene Patala Formation to assess its source rock potential,organic matter types and thermal maturity levels in the Margalla Hill Range of North Pakistan.Source rock generative potential,kerogen types and thermal maturation of the analysed rock samples were unraveled by using Rock-Eval pyrolysis T_(max),TOC(total organic carbon)and vitrinite reflectance(R_(0))analyses.TOC analysis coupled with S_(2) yield revealed poor to fair source rock quality encountered within the formation.The pyrolysis T_(max) vs Hydrogen Index(HI),showed mostly Type Ⅲ kerogen dominated by thermally immature to mature organic matter.The HI and genetic potential is low and revealed poor hydrocarbon generation potential of the formation.The S_(1) vs TOC plots confirm the indigenous nature of the hydrocarbons hosted by Patala Formation.The vitrinite reflectance outcomes indicated immature to mature source rock beds lying in dry gas zone.The HI and OI signatures and abundance of Type Ⅲ kerogen are indicating dominance of terrestrial organic matter within the formation.Overall,the investigated Patala Formation exposed at the studied section of Margalla Hill Range,Pakistan acts as a poor source rock unit for liquid hydrocarbon generation but holds prospects for dry gas generation in the study area.

In-situ Fluid Phase Variation along the Thermal Maturation Gradient in Shale Petroleum Systems and Its Impact on Well Production Performance

In-situ fluid phase behavior is important in determining hydrocarbon contents and the multiphase flow through shale reservoirs.The gas-to-oil ratio(GOR) has been recognized as a critical indicator of fluid types.However,little is known about the impact of fluid phase variation across the thermal maturity on shale oil/gas production(e.g.,estimated ultimate recovery,EUR).According to the specific gravity ratio of oil/gas,the producing GOR was converted and normalized into a mass fraction of gas in total hydrocarbons(MGOR) to compare North American shale oil/gas plays with Chinese shale oil and hybrid gas-condensate plays.A correlation between MGOR,the fluid phases,and production data was established to identify five phase stages of flow.MGORvaries systematically with the different production zones,which shows promise in rapidly indicating the well production performance and high production stages of shale oil/gas plays.The hybrid shale gas condensate index,Tmax,and total gas contents were integrated to present the fluid types and maturity of shale gas-condensates,which indicates fluid phase and production variation across thermal evolution.The results offer a unique perspective on the shale oil reservoir producibility based on the impact of GOR on fluid phases and EUR from the dominant global oil/gas plays.

Application of Statistical Methods to Biomarkers for Geochemical Evaluation and Genetic Type Determination of Gas Condensates in the Persian Gulf and Coastal Fars,Southern Iran

In a comprehensive geochemical study,the genetic relationships among 14 samples of gas condensates from the Persian Gulf were investigated for the purpose of evaluating the respective source rocks in terms of both age and sedimentary paleoenvironment.Chemometric analysis was used for categorization and determination of a certitude range to determine the genetic type of the condensate families in the studied basin.The samples were collected from Late Permian-Triassic reservoirs(Dalan and Kangan formations)located in 6 gasfields(gas condensate)hosting some of Iran’s most important gas/gas condensate reserves.Obtained by gas chromatography-mass spectrometry(GC-MS),a total of 16 biomarker parameters(10 maturity-related parameters and 6 sedimentary environment-related parameters)were used to evaluate the samples in terms of thermal maturity(and hence their positions in the maturity chart),the sedimentary environment of the source rock and the lithology.Application of Hierarchical Clustering Analysis(HCA)and Principal Component Analysis(PCA)to the collected data led to the categorization of the samples into three main genetic groups,Ⅰ-Ⅲ.GroupsⅠandⅢwere found to be located in the east and the west of the Persian Gulf,respectively,while GroupⅡwas developed between the two other groups.

Evaluation of Highly Thermally Mature Shale-Gas Reservoirs in Complex Structural Parts of the Sichuan Basin

Successful exploration and development of shale-gas in the United States and Canada suggest a new solution to the energy problem in China. The Longmaxi （~1~） Formation in the Si- chuan （[~）1[） Basin is regarded as a strong potential play for shale-gas with the following significant features： （1） complex structural types caused by multiphase tectonic superposition and reconstruction; （2） varied slippage processes that enhance porosity and permeability; （3） high thermal maturation of organic matter （Ro〉2.5%）; （4） high brittle mineral contents; （5） high and constant thicknesses of shale horizons within the formation. Evaluation of shale-gas prospects in this area should consider not only hydrocarbon parameters, but also preservation conditions and structural stability. Data from several new exploration wells in the Sichuan Basin indicate that tectonically induced net-shaped fractures ef- fectively enhance shale reservoir properties. Structural types providing favorable storage conditions for shale-gas are described and evaluated. The high-yielding shale gas reservoir shares the same characte- ristics of conventional gas reservoirs except for its consubstantial source rock and reservoir in South China.

Maturity Assessment of the Lower Cambrian and Sinian Shales Using Multiple Technical Approaches

The Lower Cambrian Niutitang and Sinian Doushantuo shales are the most important and widespread source rocks and target layers in South China. Reliable data of the thermal maturity of organic matter(OM) is widely used to assess hydrocarbon generation and is a key property used in determining the viability and hydrocarbon potential of these new shales. Nevertheless, traditional thermal maturity indicators are no longer suited to the vitrinite-lack marine shales. This study aims to combine high throughput Raman and infrared spectroscopy analysis to confirm and validate the thermal maturity in comparison with the bitumen reflectance(R_(b)). Raman parameters such as the differences between the positions of the two bands(V_(G)–V_(D)) are strong parameters for calculating the thermal maturity in a large vitrinite reflectance(R_(o)) ranging from 1.60% to 3.80%. The infrared spectroscopy analysis indicates that the aromatic C=C bands and CH_(2)/CH_(3) aliphatic groups both are closely correlated with thermal maturity. The calculated R_(o) results from Raman and infrared spectroscopy are in strong coincidence with the R_(b). The relationships between R_(b) and pore volumes/surface areas(calculated from N_(2) adsorption) indicate that the sample with R_(b) of 3.40% has the lowest pore volumes and surface areas. Focused ion beam scanning electron microscopy(FIB-SEM) observations of OM pores indicate that R_(o) of approximately 3.60% may be an upper limit for OM porosity development. Obviously, kerogen Raman and infrared spectroscopy can indicate methods for reducing the risk in assessing maturity with practical, low-cost accurate results. Exploration of shale gas in the high maturity(>3.40%–3.60%) region carries huge risks.