Hydrocarbon Generation Capacity Research Articles

Effective Attributes Quantification to Bridge Gap between Elastic Properties and Reservoir Parameters in Self-Resource Rocks

The successful production of unconventional resources such as shale gas is highly dependent on its two reservoir properties, organic matter and rock brittleness. High resolution spatially characterization of these two unconventional reservoir properties needs surface reflection seismic data. However, to delineate these two parameters on seismic scale is a challenging task because poor correlation is observed between these parameters and elastic properties of the rock. To encounter this adversity in current study we proposed effective attributes method in which organic shale reservoir properties are divided into their hard and soft elastic response. From the analysis of worldwide laboratory dataset, we find that hard and soft components have shown us much better linear correlation with P- and S- wave impedance. The proposed effective attributes, helped us to reduce the gap between unconventional reservoir properties and seismic characteristics. These attributes are the main controlling factor for rock elastic properties and exhibit information about hydrocarbon generation capacity and rock brittleness. A well data example from Sembar shale has also shown successful results for proposed effective attributes methodology. These attributes application on inverted P-wave impedance seismic data of employed organic shale reservoir have shown productive results to quantify its unconventional prospect on seismic scale. The approach used in this study can be confidently employed to assess unconventional reservoir potential in other parts of the world.

Distribution Characteristics and Accumulation Model for the Coal‐formed Gas Generated from Permo‐Carboniferous Coal Measures in Bohai Bay Basin, China: A Review

Coal‐formed gas generated from the Permo‐Carboniferous coal measures has become one of the most important targets for deep hydrocarbon exploration in the Bohai Bay Basin, offshore eastern China. However, the proven gas reserves from this source rock remain low to date, and the distribution characteristics and accumulation model for the coal‐formed gas are not clear. Here we review the coal‐formed gas deposits formed from the Permo‐Carboniferous coal measures in the Bohai Bay Basin. The accumulations are scattered, and dominated by middle‐small sized gas fields, of which the proven reserves ranging from 0.002 to 149.4×108 m3 with an average of 44.30×108 m3 and a mid‐point of 8.16×108 m3. The commercially valuable gas fields are mainly found in the central and southern parts of the basin. Vertically, the coal‐formed gas is accumulated at multiple stratigraphic levels from Paleogene to Archaeozoic, among which the Paleogene and Permo‐Carboniferous are the main reservoir strata. According to the transporting pathway, filling mechanism and the relationship between source rocks and reservoir, the coal‐formed gas accumulation model can be defined into three types: “Upward migrated, fault transported gas” accumulation model, “Laterally migrated, sandbody transported gas” accumulation model, and “Downward migrated, sub‐source, fracture transported gas” accumulation model. Source rock distribution, thermal evolution and hydrocarbon generation capacity are the fundamental controlling factors for the macro distribution and enrichment of the coal‐formed gas. The fault activity and the configuration of fault and caprock control the vertical enrichment pattern.

Application of fine analysis technology for gas-source on condensate gas reservoirs in the Dinan Uplift

Some researches on the distribution of Carboniferous source rock in the Dinan uplift, Junggar Basin, has been clear that the Songkaersu Formation (C1sb) is relatively implement, but that of the Dishuiquan Formation (C1d) is still uncertain. The acknowledgment and conclusion of the hydrocarbon generation and gas generation capacity of C1d source rocks are fairly limited, and thus the contribution of this set of source rock to the natural gas in the southern Dinan uplift exists a certain dispute. In this paper, based on the predecessors’ research work, the fine-scale comparison of fingerprint characteristics between the two sets of source rocks in Carboniferous by using monomer hydrocarbon carbon isotope technique, and at the same time, the condensate oils which were associated with Carboniferous natural gas in this region were also compared in detail. As such, the contribution of Carboniferous C1sb and C1d source rocks was determined.

The Rock-Eval Pyrolysis and Hydrocarbon Generation Kinetic of Four Coal Samples from Different Areas, China

Rock-Eval pyrolysis and hydrocarbon generation kinetic are effective and extensive methods to evaluate source rock. In this study, we chose four coal samples from different areas in China including Fuxing, Guangyuan, Fushun and Taiyuanzu. The results show that Fushun has the highest hydrocarbon generation capacity (399-427mg/g), the lowest dominant activation energy (47Kcal/mol) and frequency factor (1.32*1012/s), which has the highest transformation ratio at different heating rates. It is easy to evaluate the hydrocarbon potential of Fushun. But Fuxing, Guangyuan and Taiyuanzu have different frequency factors and activation energies. In the multiple frequency factors (MFF) model, it is difficult to evaluate hydrocarbon potential by activation energies when frequency factors are different. This study evaluates hydrocarbon potential by comparing transformation ratio at universal and geological heating rate. This is because transformation ratio is a comprehensive result of frequency factor and activation energy. In addition, different heating rates affect the hydrocarbon generation rate of coal samples, the hydrocarbon generation rate is positive with heating rates. For example, the hydrocarbon generation rate of Fushun at 5, 25°C/min are 0.0013 and 0.0051 mg/g.s1. And the temperature difference (AT) of main hydrocarbon generation period heated at 3°C/my and 5, 15, 25°C/min are different, which are 21-52 and 53-99°C.

Forming a new small sample deep learning model to predict total organic carbon content by combining unsupervised learning with semisupervised learning

The total organic carbon (TOC) content is a parameter that is directly used to evaluate the hydrocarbon generation capacity of a reservoir. For a reservoir, accurately calculating TOC using well logging curves is a problem that needs to be solved. Machine learning models usually yield the most accurate results. Problems of existing machine learning models that are applied to well logging interpretations include poor feature extraction methods and limited ability to learn complex functions. However, logging interpretation is a small sample problem, and traditional deep learning with strong feature extraction ability cannot be directly used; thus, a deep learning model suitable for logging small sample features, namely, a combination of unsupervised learning and semisupervised learning in an integrated DLM (IDLM), is proposed in this paper and is applied to the TOC prediction problem. This study is also the first systematic application of a deep learning model in a well logging interpretation. First, the model uses a stacked extreme learning machine sparse autoencoder (SELM-SAE) unsupervised learning method to perform coarse feature extraction for a large number of unlabeled samples, and a feature extraction layer consisting of multiple hidden layers is established. Then, the model uses the deep Boltzmann machine (DBM) semisupervised learning method to learn a large number of unlabeled samples and a small number of labeled samples (the input is extracted from logging curve values into SELM-SAE extracted features), and the SELM-SAE and DBM are integrated to form a deep learning model (DLM). Finally, multiple DLMs are combined to form an IDLM algorithm through an improved weighted bagging algorithm. A total of 2381 samples with an unlabeled logging response from 4 wells in 2 shale gas areas and 326 samples with determined TOC values are used to train the model. The model is compared with 11 other machine learning models, and the IDLM achieves the highest precision. Moreover, the simulation shows that for the TOC prediction problem, when the number of labeled samples included in the training is greater than 20, even if this number of samples is used to train 10 hidden layer IDLMs, the trained model has a very low overfitting probability and exhibits the potential to exceed the accuracies of other models. Relative to the existing mainstream shallow model, the IDLM based on a DLM provides the most advanced performance and is more effective. This method implements a small sample deep learning algorithm for TOC prediction and can feasibly use deep learning to solve logging interpretation problems and other small sample set problems for the first time. The IDLM achieves high precision and provides novel insights that can aid in oil and gas exploration and development.

Quantification models of overpressuring in Paleogene source rocks of the Raoyang Depression, Bohai Bay Basin, China

Abstract Much progress in studies on the quantifications of overpressuring has been made during the past decades, and various quantitative models for the overpressure have been built based on overpressure transfer, tectonic extrusion, disequilibrium compaction, hydrocarbon generation, and other processes. In the Raoyang Depression of the Bohai Bay Basin in China, overpressure is mainly generated due to disequilibrium compaction and hydrocarbon generation. However, the overpressure-generation mechanism varies significantly in the overpressured formations and sags. The overpressure genesis in the Dongying Formation (Ed) occurs by disequilibrium compaction, but the overpressure mechanism in the first member (Es1) and third member (Es3) of the Shahejie Formation is a combination of disequilibrium compaction and hydrocarbon generation. The overpressure is caused by the difference in hydrocarbon generation before and after hydrocarbon expulsion. On the basis of the law of volume conservation, three quantitative models have been established for the under-compacted interval, the hydrocarbon-generation-to-expulsion interval, and the post-hydrocarbon-expulsion interval. The contribution of hydrocarbon generation differs in four sags developed in the Raoyang Depression due to differences in the hydrocarbon-generation capacity. Calculations based on these quantitative models indicated that the contributions of hydrocarbon generation to overpressure at the bottom of the Es1 and Es3 members in the Maxi Sag are 54.3% and 39.1%, respectively. The excessive pressure in the lower strata was stronger than that in the upper strata due to the fact that the contribution ratio of hydrocarbon generation to overpressure in the Es1 member is lower than that in the Es3 member, unlike in the case when the pressure in the upper strata is stronger than that in the lower strata. Therefore, it indicated that hydrocarbon generation plays an important role in the overpressure-generation mechanism.

Geochemical characteristics and genesis of pre-salt gases in the Ordos Basin, China

The geochemical characteristics, genesis and accumulation mechanism of the pre-salt gases of Ordos Basin have been rarely studied in China. Components and carbon isotope values of pre-salt gases are investigated and compared with those of the Upper Paleozoic and post-salt gases. Homogenization temperatures and carbon isotope values of gases of the pre-salt fluid inclusions were also measured. Based on the geochemical parameters, combined with the geological conditions, the genesis and accumulation mechanism of pre-salt gases are studied. The components, carbon isotope values and the first two homogenization temperature ranges (90–120 °C and 120–160 °C) of the pre-salt gases contain those of the Upper Paleozoic and post-salt gases. The pre-salt inclusions have an extra homogenization temperature range (160–200 °C) and the pre-salt rocks also have some hydrocarbon generation capacity, which means the pre-salt rocks may also generate some gases. The pre-salt gases are mixed gases generated from the Upper Paleozoic coal strata, the post-salt and pre-salt Lower Paleozoic Majiagou Formation, which is confirmed by the geochemical characteristics and the geological settings.

Effect of shale diagenesis on pores and storage capacity in the Paleogene Shahejie Formation, Dongying Depression, Bohai Bay Basin, east China

Abstract Compared to other marine-shale gas reservoirs in South China, the shale that developed in faulted basins in East China possesses peculiar characteristics regarding the mineral types and their evolution. The diagenesis of inorganic minerals, generation of hydrocarbons, and evolution of organic matter control the final features and quality of these shale reservoirs. Therefore, we must analyze this diagenesis based on the essential characteristics of the representative reservoir and discuss the influence of the diagenesis' evolution stage on the shale reservoir. This topic is also of practical value for contemporary shale-oil exploration and development. In this paper, we observe diagenesis, study its essential characteristics (such as the structure of the reservoir and pores), determine the key factors that control the reservoir's storage capacity, and analyze the role of diagenesis (organic and inorganic) in the evolution of pores and the reservoir's storage capacity. The mineral types are diverse, and the content of calcite and other carbonate minerals is generally very high. Organic matter is abundant, thermal evolution is low, and the hydrocarbon generation capacity is strong. Because of their high variability, some pores are hard to differentiate from microfractures. Dissolved pores, which are generated by intercrystalline pores and the dissolution of calcite, dolomite, and other carbonate mineral grains, are the major component of a macroporous matrix. The large proportion of hydrocarbons that are generated by solid organic matter leads to the accumulation of pressure. The shale generates a high number of microfractures, which form a reservoir space network system that increases the porosity of the reservoir. Dolomite has a unique supporting role for the matrix pores, leading to the development of a matrix pore-seam system. The reservoir's mineral composition, pore diameter, porosity, and organic-matter content determine the reservoir properties and oil saturation. Organic-rich laminated shale has the best physical properties, dominated by macro-pores and easily connected and merged pore seams. The massive shale has the poorest reservoir property. The development and evolution of pores are mainly controlled by the transformation of clay minerals, the content of carbonate minerals, the sedimentary structure and the intensity of diagenesis. Dissolution depends on the intensity of hydrocarbon generation, the expulsion of acid by organic matter, the state of the carbonate minerals and organic matter, and the smooth depression of the fluid environment. Organic diagenesis is closely related to the diagenesis and evolution of inorganic matter and is typically reflected in the recrystallization of calcite, abundance of organic matter, and hydrocarbon generation by organic matter. A local alkaline diagenetic fluid environment and reduction in the degree of hydrocarbon generation transform incremental porosity to pore reduction. Favorable lithofacies and advantageous layer sections should be selected by considering the stage of diagenesis evolution.

Evolution characteristics and model of nanopore structure and adsorption capacity in organic-rich shale during artificial thermal maturation: A pyrolysis study of the Mesoproterozoic Xiamaling marine shale with type II kerogen from Zhangjiakou, Hebei, China

Thermal maturity has a considerable impact on hydrocarbon generation, mineral conversion, nanopore structure, and adsorption capacity evolution of shale, but that impact on organic-rich marine shales containing type II kerogen has been rarely subjected to explicit and quantitative characterization. This study aims to obtain information regarding the effects of thermal maturation on organic matter, mineral content, pore structure, and adsorption capacity evolution of marine shale. Mesoproterozoic Xiamaling immaturity marine oil shale with type II kerogen in Zhangjiakou of Hebei, China, was chosen for anhydrous pyrolysis to simulate the maturation process. With increasing simulation temperature, hydrocarbon generation and mineral transformation promote the formation, development, and evolution of pores in the shale. The original and simulated samples consist of closed microspores and one-end closed pores of the slit throat, all-opened wedge-shaped capillaries, and fractured or lamellar pores, which are related to the plate particles of clay. The increase in maturity can promote the formation and development of pores in the shale. Heating can also promote the accumulation, formation, and development of pores, leading to a large pore volume and surface area. The temperature increase can promote the development of pore volume and surface area of 1–10 and 40-nm diameter pores. The formation and development of pore volume and surface area of 1–10 nm diameter pores are more substantial than that of 40-nm diameter pores. The pore structure evolution of the sample can be divided into pore adjustment (T < 350°C, EqRo < 0.86%), development (350°C < T < 650°C, 0.86% < EqRo < 3.28%), and conversion or destruction stages (T > 650°C, EqRo > 3.28%). Along with the increase in maturity, the methane adsorption content decreases in the initial simulation stage, increases in the middle simulation stage, and reaches the maximum value at 650°C, after which it gradually decreases. A general evolution model is proposed by combining the nanopore structure and the adsorption capacity evolution characteristics of the oil shale.

The contribution of bacteria to organic matter in coal-measure source rocks

On the basis of GC–MS analysis, a suite of nine coal-measure source rocks (Ro 0.51%–0.63%) from the southern margin of Junggar basin was found to contain many biomarkers for bacterially-generated hydrocarbons: hopane, sesquiterpene, C23+ monomethyl alkanes (even carbon predominance), and C24+ alkyl cyclohexane. Rock–eval and microscope analysis indicate that vitrinite (especially desmocollinite and homocollinite) plays a significant role in the generation of hydrocarbons in coal-measure source rocks. Vitrinite performs this role by absorbing ultramicroscopic organic matter, generally in the form of resins or bacterial plastids. C23+ monomethyl alkanes (even carbon predominance) and C24+ alkyl cyclohexane series compounds are derived from bacterial metabolites of higher plants. The ultramicro organic matter adsorbed by vitrinite source rocks in the study area is probably ultramicro bacterial plastids. Because the organic matter of higher plants with low hydrogen content has been transformed into organic matter rich in hydrogen by bacteria, the hydrocarbon generation capacity of source rocks is greatly improved. In other words, in coal-measure source rocks, bacteria play an important role in hydrocarbon generation.

Geochemical characteristics and hydrocarbon generation potential of the first member of Shahejie Formation (E2s1) source rocks in the Dongpu Depression, East China

The Dongpu Depression, containing huge amounts of hydrocarbons, is a typical petroliferous province in the Bohai Bay Basin, east China. As one set of the main source rocks, the first member of Shahejie Formation (E2s1) shows huge exploration potential with approximately 0.83 × 108 t resources remaining to be discovered. However, the geochemical characteristics and thermal evolution history of E2s1 source rocks have still not been determined. In this study, the sedimentary features were firstly analysed based on the geological data. Then the organic matter abundance, kerogen type, and thermal maturity of E2s1 source rocks in the present day were evaluated according to the Rock‐Eval pyrolysis, micro‐components of kerogen, total organic carbon (TOC), and vitrinite reflectance analysis. Furthermore, the evolution of thermal history and hydrocarbon generation was determined using the PetroMod procedure. The results show that dark mudstones and salt rocks were well developed in E2s1, which are propitious for organic matter to grow and preserve. E2s1 source rocks contain abundant organic matter and moderate to good generative source rock potential. E2s1 source rocks mainly consist of Type II kerogen and have entered early to maturation stage for hydrocarbon generation. Due to the limited buried depth, E2s1 source rocks only attained lower thermal maturity and generated finite hydrocarbons. The initial rapid subsidence and the second rift after uplift erosion resulted in the higher geo‐temperature at the end of E3d and the present day. Corresponding to the geo‐temperature evolution, there are two stages of hydrocarbon generation for E2s1 source rocks: The first stage was in the late E3d period, and the late stage was from the late Neogene to the present day. Moreover, the hydrocarbon generation rate and quantity of the late stage are much higher than the first stage, indicating the major hydrocarbon generation stage. Due to the limited hydrocarbon generation capacity, oils generated from E2s1 source rocks are low maturity; thus, it cannot migrate for a long distance and only accumulated around the sag belts.

Lower limit of thermal maturity for the carbonization of organic matter in marine shale and its exploration risk

Abstract Based on the drilling data of the Silurian Longmaxi Formation in the Sichuan Basin and periphery, SW China, the Ro lower limits and essential features of the carbonization of organic matter in over-high maturity marine shale were examined using laser Raman, electrical and physical property characterization techniques. Three preliminary conclusions are drawn: (1) The lower limit of Ro for the carbonization of Type I-II1 organic matter in marine shale is 3.5%; when the Ro is less than 3.4%, carbonization of organic matter won't happen in general; when the Ro ranges from 3.4% to 3.5%, non-carbonization and weak carbonization of organic matter may coexist; when the Ro is higher than 3.5%, the carbonization of organic matter is highly likely to take place. (2) Organic-rich shale entering carbonization phase have three basic characteristics: log resistivity curve showing a general “slender neck” with low-ultralow resistance response, Raman spectra showing a higher graphite peak, and poor physical property (with matrix porosity of only less than 1/2 of the normal level). (3) The quality damage of shale reservoir caused by the carbonization of organic matter is almost fatal, which primarily manifests in depletion of hydrocarbon generation capacity, reduction or disappearance of organic pores and intercrystalline pores of clay minerals, and drop of adsorption capacity to natural gas. Therefore, the lower limit of Ro for the carbonization of Type I-II1 organic matter should be regarded as the theoretically impassable red line of shale gas exploration in the ancient marine shale formations. The organic-rich shale with low-ultralow resistance should be evaluated effectively in area selection to exclude the high risk areas caused by the carbonization of organic matter. The target organic-rich shale layers with low-ultralow resistance drilled during exploration and development should be evaluated on carbonization level of organic matter, and the deployment plan should be adjusted according to the evaluation results in time.

Ultra-deep Permian coal gas reservoirs of the Cooper Basin: insights from new studies

There is a vast, untapped gas resource in deep coal seams of the Cooper Basin, where extensive legacy gas infrastructure facilitates efficient access to markets. Proof-of-concept for the 5 million acre (20 000km2) Cooper Basin Deep Coal Gas (CBDCG) Play was demonstrated by Santos Limited in 2007 during the rise of shale gas. Commercial viability on a full-cycle, standalone basis is yet to be proven. If commercial reservoirs in nanoDarcy matrix permeability shale can be manufactured by engineers, why not in deep, dry, low-vitrinite, poorly cleated coal seams having comparable matrix permeability but higher gas content? Apart from gas being stored in a source rock reservoir format, there is little similarity to other unconventional plays. Without an analogue, development of an optimal reservoir stimulation technology must be undertaken from first principles, using deep coal-specific geotechnical and engineering assumptions. Results to date suggest that stimulation techniques for other unconventional reservoirs are unlikely to be transferable. A paradigm shift in extraction technology may be required, comparable to that devised for shale reservoirs. Recent collaborative studies between the South Australian Department of State Development, Geological Survey of Queensland and Geoscience Australia provide new insight into the hydrocarbon generative capacity of Cooper Basin coal seams. Sophisticated regional modelling relies upon a limited coal-specific raw dataset involving ~90 (5%) of the total 1900 wells penetrating Permian coal. Complex environmental overprints affecting resource concentration and gas flow capacity are not considered. Detailed resource estimation and the detection of anomalies such as sweet spots requires the incorporation of direct measurement. To increase granularity, the authors are conducting an independent, basin-wide review of underutilised open file data, not yet used for unconventional reservoir purposes. Reservoir parameters are quantified for seams thicker than 10feet (3m), primarily using mudlogs and electric logs. To date, ~3750 reservoir intersections are characterised in ~1000 wells. Some parameters relate to resource, others to extraction. A gas storage proxy is generated, not compromised by desorption lost gas corrections. A 2016 United States Geological Survey resource assessment, based on Geoscience Australia studies, suggests that the Play remains a world-class opportunity, despite being technology-stranded for the past 10years. Progress has been made in achieving small but incrementally economic flow rates from add-on hydraulic fracture stimulation treatments inside conventional gas fields. Nevertheless, a geology/technology impasse precludes full-cycle, standalone commercial production. A review of open file data and cross-industry literature suggests that the root cause is the inability of current techniques to generate the massive fracture network surface area essential for high gas flow. Coal ductility and high initial reservoir confining stress are interpreted to be responsible. Ultra-deep coal reservoirs, like shale reservoirs, must be artificially created by a large-scale stimulation event. Although coal seams fail the reservoir ‘brittleness test’ for shale reservoir stimulation practices, the authors conclude from recent studies that pervasive, mostly cemented or closed coal fabric planes of weakness may instead be reactivated on a large scale, to create a shale reservoir-like stimulated reservoir volume (SRV), by mechanisms which harness the reservoir stress reduction capacity of desorption-induced coal matrix shrinkage.

Geological control factors of micro oil distribution in tight reservoirs

Understanding the oil distribution characteristics in unconventional tight reservoirs is crucial for hydrocarbon evaluation and oil/gas extraction from such reservoirs. Previous studies on tight oil distribution characteristics are mostly concerned with the basin scale. Based on Lucaogou core samples, geochemical approaches including Soxhlet extraction, total organic carbon (TOC), and Rock-Eval are combined with reservoir physical approaches including mercury injection capillary pressure (MICP) and porosity-permeability analysis, to quantitatively evaluate oil distribution of tight reservoirs on micro scale. The emphasis is to identify the key geological control factors of micro oil distribution in such tight reservoirs. Dolomicrites and non-detrital mudstones have excellent hydrocarbon generation capacity while detritus-containing dolomites, siltstones, and silty mudstones have higher porosity and oil content, and coarser pore throat radius. Oil content is mainly controlled by porosity, pore throat radius, and hydrocarbon generation capacity. Porosity is positively correlated with oil content in almost all samples including various lithologies, indicating that it is a primary constraint for providing storage space. Pore throat radius is also an important factor, as oil migration is inhibited by the capillary pressure which must be overcome. If the reservoir rock with suitable porosity has no hydrocarbon generation capacity, pore throat radius will be decisive. As tight reservoirs are generally characterized by widely distributed nanoscale pore throats and high capillary pressure, hydrocarbon generation capacity plays an important role in reservoir rocks with suitable porosity and fine pore throats. Because such reservoir rocks cannot be charged completely. The positive correlation between hydrocarbon generation capacity and oil content in three types of high porosity lithologies (detritus-containing dolomites, siltstones, and silty mudstones) supports this assertion.

Model-assisted Rock-Eval data interpretation for source rock evaluation: Examples from producing and potential shale gas resource plays

Rock-Eval pyrolysis has been widely accepted by the petroleum industry as a useful technique for a quick, easy and cost effective source rock evaluation. However, there are misconceptions and misuse of some of the existing Rock-Eval parameters due to implicit underlying assumptions or poor understanding of the limitations, which could lead to erroneous conclusions. Data interpretation from a perspective of hydrocarbon generation kinetics may facilitate better interpretation of the hydrocarbon generation capacity of a source rock from its thermal stability and transformational behaviors. We present a model-assisted approach for data interpretation, from which data scatters can be viewed not only for the remaining petroleum generation potential of individual samples, but also for data specific thermal decomposition path as a whole to verify whether the data come from a single kerogen population with similar kinetics and associated generation potentials. Moreover, we propose a concept of dimensionless TOC and S2 variables that effectively removes the thermal maturity overprint in the traditional TOC vs. S2 plot used for the determination of the kerogen type. The dimensionless variables are defined by rescaling the parameters against their original values before thermal decomposition. On a dimensionless plot, data points from the same genetic population of source rocks align on a single line regardless of their thermal maturation levels. This article demonstrates the methods and the proposed approaches for studying oil generation kinetics and resource potential using traditional Rock-Eval data through examples from selected producing and potential shale gas plays in Canadian sedimentary basins and elsewhere.

Sweet spot identification in underexplored shales using multidisciplinary reservoir characterization and key performance indicators: Example of the Posidonia Shale Formation in the Netherlands

Sweet spot identification in underexplored shale gas basins needs to be based on a limited amount of data on shale properties in combination with upfront geological characterization and modelling, because actual production data is usually absent. Multidisciplinary reservoir characterization and integration of modelling approaches can aid initial site selection for exploratory drilling and de-risk exploration efforts. In this study, the potential of hydrocarbon production across underexplored shale basins is analyzed using key performance indicators. A mean indicator is defined as the harmonic mean of three performance indicators that describe the potential for hydrocarbon generation, storage, and flow stimulation. The performance indicators are based on a limited number of local shale properties, i.e. vitrinite reflectance, porosity, depth, thickness, sorbed gas content and brittleness index. Values for the indicators are calculated relative to prospective North American shales (Marcellus, Bakken, Haynesville and Barnett), so that the mean indicator can be used to rank the prospectivity of an underexplored shale relative to hydrocarbon producing shales. The mean performance indicator is also used to map out the potential for gas production in the underexplored Posidonia Shale Formation in the West Netherlands Basin. The analysis shows that the performance indicator is lower for the Posidonia than for the North American Shales, mainly due to low maturity and brittleness. Local maxima of the indicator correlate with local maxima in vitrinite reflectance and depth. Besides the low potential for flow stimulation, the potential for hydrocarbon generation and storage capacity of the Posidonia are comparable to oil-window thermal-maturity Barnett Shale. Upfront simulations of hydraulic fracture properties and gas production in the Posidonia Shale Formation are in rough agreement with observed average gas flow for Barnett wells in non-core areas that are oil mature. It shows that key performance indicators can be applied to underexplored shales to quantify prospectivity and map out sweet spots across shale basins.

Oil content in argillaceous dolomite from the Jianghan Basin, China: Application of new grading evaluation criteria to study shale oil potential

Shale oil resources are found in the argillaceous dolomite in the Xingouzui Formation of the Jianghan Basin. The grading evaluation criteria based on the oil content was established to discuss the shale oil potential. The parameter of hydrocarbon potential index, (S1+S2)/TOC×100, suggests that the hydrocarbon potential of the argillaceous dolomite becomes lower significantly with the type of kerogen changing from I to III. However, a corresponding decrease in the amount of residual hydrocarbon (S1/TOC) is within a small range, because the argillaceous dolomite with I and II1 kerogen (especially I kerogen) have relatively larger hydrocarbon expulsion amount. For shale oil exploration, besides type I source rocks, source rocks with II1 and II2 kerogen should also be focused. However, source rocks with III kerogen bear no exploration significance owing to the low hydrocarbon generation capacity and unfavorable molecular configuration. According to the relationship between S1 and TOC, combined with parameter of the relative oil content, the shale oil resources can be divided into four classifications: enriched resources (S1>4mg/g and S1/TOC>1), moderately enriched resources (1mg/g<S1<4mg/g and S1/TOC>1), less efficient resources (1mg/g<S1<4mg/g and S1/TOC<1), and ineffective resources (S1<1mg/g and S1/TOC<1). The continuous distribution of the oil content of the argillaceous dolomite in the Lower Xingouzui Formation can be obtained using the method of Δlog R. The enriched or moderately enriched resources are primarily distributed in the argillaceous dolomite with kerogen types I and II1. In addition, moderately enriched resources also exist in the argillaceous dolomite with kerogen type II2 in the middle and bottom of the Lower Xingouzui Formation, but the distribution is more dispersed.

Impact of hydrocarbon expulsion efficiency of continental shale upon shale oil accumulations in eastern China

Core samples were taken from two formations (the Qingshankou Formation in northern Songliao Basin and the third member of the Shahejie Formation of Zhanhua Sag) to carry out a study of impact of hydrocarbon expulsion from continental shale upon shale oil accumulations in eastern China. Total Organic Carbon (TOC) and pyrolysis data of these samples were used to establish an evaluation criterion with absolute and relative oil content indexes for determining oil potential of shale. As a result, a correspondence relationship between shale oil content and organic types was established. Factors that may affect oil content of shale were discussed through study of fractures, pore development, minerals and lithological assemblage of the samples. The results show that oil content of mature petroleum source rocks is firstly controlled by fracture growth and secondly by pore development. They played both negative and positive roles in hydrocarbon flow and accumulation in shale. Overpressure caused by hydrocarbon generation and existence of organic acid corrosion are two important factors affecting the formation of fractures and pores in shale, respectively. Intervals with type I organic matter are not favorable shale oil exploration targets because they contain little oil. Shale with type I organic matter tends to generate large amount of hydrocarbon, but these hydrocarbon will escape with a high efficiency through over-pressurized fractures caused by hydrocarbon generation and lack of pore space, which in turn is the result of absence of oxygen that is essential for forming organic acid to create secondary pores in shale. On the contrary, intervals with type II organic matters are potential shale oil exploration targets for that they offered just right conditions for oil to stay inside: higher content of oxygen that is helpful in forming organic acid, moderate hydrocarbon generation capacity that will not cause over-pressurized fractures in shale with secondary pores. While intervals with type III organic matter bear no exploration significance due to the fact that this type of kerogen produces less oil because of low hydrocarbon generation capacity and unfavorable molecular configuration. Shale intervals with thin sandstone interbeds provide favorable passageways for dissolved carbonate by organic acid to flow out, avoiding secondary precipitation. The pores left behind can be excellent space for generated hydrocarbon to linger around. These interbeds are also favorable for later reservoir stimulation measures such as hydraulic fracturing. Shale oil exploration shall be focused on finding sweet spots with greater pores, which are the main reservoir space.

An analysis of natural gas exploration potential in the Qiongdongnan Basin by use of the theory of “joint control of source rocks and geothermal heat”

The Oligocene Yacheng Fm contains the most important source rocks that have been confirmed by exploratory wells in the Qiongdongnan Basin. The efficiency of these source rocks is the key to the breakthrough in natural gas exploration in the study area. This paper analyzes the hydrocarbon potential of each sag in this basin from the perspective of control of both source rocks and geothermal heat. Two types of source rocks occur in the Yacheng Fm, namely mudstone of transitional facies and mudstone of neritic facies. Both of them are dominated by a kerogen of type-III, followed by type-II. Their organic matter abundances are controlled by the amount of continental clastic input. The mudstone of transitional facies is commonly higher in organic matter abundance, while that of neritic facies is lower. The coal-measure source rocks of transitional facies were mainly formed in such environments as delta plains, coastal plains and barrier tidal flat-marshes. Due to the control of Cenozoic lithosphere extension and influence of neotectonism, the geothermal gradient, terrestrial heat flow value (HFV) and level of thermal evolution are generally high in deep water. The hot setting not only determines the predominance of gas generation in the deep-water sags, but can promote the shallow-buried source rocks in shallow water into oil window to generate oil. In addition to promoting the hydrocarbon generation of source rocks, the high geothermal and high heat flow value can also speed up the cracking of residual hydrocarbons, thus enhancing hydrocarbon generation efficiency and capacity. According to the theory of joint control of source quality and geothermal heat on hydrocarbon generation, we comprehensively evaluate and rank the exploration potentials of major sags in the Qiongdongnan Basin. These sags are divided into 3 types, of which type-I sags including Yanan, Lingshui, Baodao, Ledong and Huaguang are the highest in hydrocarbon exploration potential.

Hydrocarbon Preservation in Marine Strata of the Middle-Upper Yangtze Block, Southwest China

The hydrocarbon generative capacity is high in the Middle-Upper Yangtze Block, southwest China. However the hydrocarbon cap rocks are severely deformed. Preservation has become key to oil and gas exploration. In this study, by evaluating total dissolved solids of formation water, hot spring temperature, δ13C and δ18O isotopes, and δD and δ18O isotopes of calcite veins and δD and δ18O isotopes of fluid inclusions, the hydrocarbon preservation can be inferred. Hydrocarbon preservation in the southeast is better than that of the northwest.