Unconventional Petroleum Systems Research Articles

The unconventional petroleum system of a mixed siliciclastic-carbonate sequence: Irati Formation, Paraná Basin, Brazil

Widespread rhythmic intercalation of a millimeter- to meter-scale hydrocarbon source rock (organic-rich shale and marlstone) and a carbonate reservoir (micritic and peloidal dolostone) are unusual. Here, the case of the Irati Formation (Paraná Basin) is reported, in which source rock strata have high total organic carbon (averaging 10 to 20 wt%), with dominance of highly oil-prone kerogen type I and II. Multivariate statistical analyses were applied to find patterns in the geochemical multivariate data set. The data points to three main productive sectors in the basin: Paraná Sector, Santa Catarina Sector, and Rio Grande do Sul Sector. Quality, quantity, and petroleum potential vary both laterally and vertically. On the other hand, the reservoir carbonate beds are predominantly composed of low-primary pore space, in which the effective reservoir capacity is determined by the presence of postdepositional secondary porosity. In addition, the Paraná-Etendeka magmatism, which occurred during the break-up of the Atlantic Ocean, played an important role in thermal maturation and primary oil migration.

Stress-Dependent Petrophysical Properties of the Bakken Unconventional Petroleum System: Insights from Elastic Wave Velocities and Permeability Measurements

The net-effective stress is a fundamental physical property that undergoes dynamic changes in response to variations in pore pressure during production and injection activities. Petrophysical properties, including porosity, permeability, and wave velocities, play a critical role and exhibit strong dependence on the mechanical stress state of the formation. The Williston basin’s Bakken Formation represents a significant reservoir of hydrocarbons within the United States. To investigate this formation, we extracted core plugs from three distinct Bakken members, namely Upper Bakken, Middle Bakken, and Lower Bakken. Subsequently, we conducted a series of measurements of ultrasonic compressional and shear wave velocities, as well as pulse decay permeabilities using nitrogen, under various confining pressures employing the Autolab-1500 apparatus. Our experimental observations revealed that the ultrasonic wave velocities and permeability display a significant sensitivity to stress changes. We investigated existing empirical relationships on velocity-effective stress, compressional-shear wave velocities, and permeability-effective stress, and proposed the best models and associated fitting parameters applicable to the current datasets. In conjunction with the acquired datasets, these models have considerable potential for use in time-lapse seismic monitoring and the study of production decline behavior. The best fitting models can be used to forecast the petrophysical and geomechanical property changes as the reservoir pore pressure is depleted due to the production, which is critical to the production forecast for unconventional reservoirs.

Geochemistry of oils and condensates from the lower Eagle Ford Formation, south Texas. Part 5: Light hydrocarbons

There is a rich history of using light hydrocarbon distributions to characterize source and thermal maturity based on observations made on source rocks and petroleum fluids produced from conventional reservoirs. In this study, a suite of lower Eagle Ford oils and condensates was used to determine the accuracy and reliability of established light hydrocarbon parameters in an unconventional petroleum system. These samples have well defined organic source facies, generative temperatures, and extent of thermal cracking. They are largely free of the influence of long-distance migration, multiple charging events, reservoir alteration processes that commonly occur in conventional accumulations and free of contributions from other reservoirs along faults induced by fracturing.All established light hydrocarbon thermal maturity parameters are influenced to varying degrees by source facies. Ratios of i-C4/n-C4 and quaternary/tertiary dimethylpentanes linearly correlate with %Ro (R2 > 0.8) with negligible sensitivity to differences in source facies. The Isoheptane and C6–C7 branched/(branched + cyclic) hydrocarbon ratios correlate with %Ro (R2 > 0.8) but also are influenced by source facies. Some established C7 parameters are affected by thermal cracking: i-C5/n-C5 and toluene/n-C7 are the most sensitive ratios to the onset of intense hydrocarbon cracking (∼1.35 %Ro) and do not appear to be significantly influenced by source facies, C6–C7 branched/(branched + normal) hydrocarbons and methylcyclohexane/n-C7 both increase in response to cracking conditions but are significantly influenced by source facies, which is likely related to the presence of reactive clays. A revised formula for Ctemp is proposed: Ctemp = 161.9 + 29.4•(ln[2,4-DMP/2,3-DMP]). The revised Ctemp formula is applicable for oils/condensates with 2,4-DMP/2,3-DMP >0.25, expanding the practical limit from ∼120 to ∼160 °C, and yields Ctemp values consistent with the maximum exposure temperature with an accuracy of ∼ ±5 °C for most samples, excluding those that have been altered by evaporation. The Mango (1997) Ctemp formula should be used for lower maturity oils having DMP/2,3-DMP values < 0.25. Sample integrity is critical as many of the light hydrocarbon parameters are significantly altered by evaporative loss.

Diagenesis of the Marinoan cap dolostone, Southern Amazon Craton: An unconventional petroleum system in the evolution of the Araras-Alto Paraguai Basin

The post-snowball Earth world favors the development of hydrocarbon source rock intimately linked to periods of post-glacial marine transgression generating important potential petroleum plays. In the Southern Amazon Craton, hydrocarbons occur in one of the most spectacular examples of post-Marinoan cap carbonate, related to the mid-Ediacaran to Early Cambrian (c. Post 635 Ma) interval associated with the early stabilization of the Gondwana Supercontinent. The Puga cap carbonate consists of the basal portion of the Araras Group exposed in the Araras Alto-Paraguai Basin inserted as a reservoir in an unconventional petroleum system. The cap dolostone overlies diamictites and is overlaid by bituminous limestone and shales (source-rock), and dolostone in the top of a 700 m-thick depositional sequence. The cap dolostone has a diachronic relation with the limestone beds typifying as a secondary reservoir characterized by bitumen-filled fenestral and interpeloidal porosity. The upper dolostone has a closed framework and acts as sealing rocks. This study aims to establish paragenesis sequence and decipher its control on the quality of the cap dolostone as a microbialites-dominated reservoir. Drill core and outcrop samples were analyzed using microfacies, scanning electron microscopy, and cathodoluminescence to unravel the diagenetic history. Aftermath, the Marinoan events favored dolomuds precipitation in the shallow platforms, preserving primary porosity and permeability reduced by early gypsum cementation during oversaturation events. Other destructive processes, such as mechanical and chemical compaction (e.g., stylolites) and authigenesis of pyrite and low-Mg ferroan calcite cementation, occurred during burial and mesodiagenesis. The low permeability restricts hydrocarbon migration concentrated in the upper cap dolostone, and the early cementation increases the potential for preserving these carbonate deposits. Hydrocarbon maturation was triggered during the burial and uplift of the Araras-Alto Paraguai basin. The cementation phases described here enhance our understanding of the mechanisms behind syndepositional diagenesis in microbially-induced reservoirs. This study uses proxies associated with diagenetic studies to quantify the quality of microbially induced dolostone reservoir linked to the evolution of the Neoproterozoic unconventional petroleum system. In addition, this conception will promote a guide for future exploration and understanding of petroleum plays and suggests a possible Precambrian source rocks component of traditional Phanerozoic Petroleum systems in the central part of Brazil.

Shale porosity measurement by the saturated oil method: Removing the contribution from oils dissolved in kerogen

Shale porosity measurements have crucial scientific and economical applications in unconventional petroleum systems. As a standard technique, liquid saturation methods, including water saturation (WS) and oil saturation (OS), have been widely used to measure the porosity of many rock types. For clay-rich shale reservoirs with high organic matter content, it is well known that the WS method may cause clay swelling and induce structural changes in the pore system. The OS method affects the accuracy of porosity measurements because of some of the oil being dissolved by kerogen within the shale; however, this has not received sufficient research attention. In this study, we compare the previously reported and newly tested OS porosities with helium (He) expansion porosity. Results show that OS porosity generally exceeds the He porosity. Furthermore, the higher the total organic carbon (TOC) content and lower the maturity of shale, the greater the difference between the OS and helium porosities. When using the OS method, the effect of kerogen-dissolved oil causes an overestimation of the shale porosity by ∼30%. To the best of our knowledge, this is the first time to note the kerogen-dissolve oil effects on OS porosity. Herein, we propose a new, simple, and effective correction method for estimating OS porosity that involves subtracting the kerogen-dissolved oil content from raw OS porosity. In addition, the quantification model of kerogen-dissolved oil capacity is established, taking into account the abundance and maturity of organic matter. Taking the He porosity as the benchmark, the absolute error of the corrected OS porosity does not exceed 1% and the average relative error is only ∼10%. The obtained results can help improve the accuracy of shale porosity evaluation methods.

Analysis of Joints Patterns in Albian to Santonian Strata on the Eastern Flank of the Abakaliki Anticlinorium: Implications on Paleostress Conditions and Fluid Flow Properties in an Unconventional Petroleum System

An analysis of joint patterns were carried out on multiple exposures in Albian to Turonian strata belonging to the Abakaliki Formation (Asu River Group) and the Eze-Aku Formation (Eze-Aku Group) on the eastern flank of the Abakaliki Anticlinorium of the Southern Benue Trough. The analysis was carried out using FracPaQ a MATLAB based toolbox for quantification of fracture patterns. The tool was used to calculate fracture density, and intensity of the traces; to quantify scaling distributions, and to determine dilation tendencies, slip tendencies, and to quantify connectivity, and fluid flow directions. Analysis show the presence of two major joint systems: A Major Cross-Fold Joint (CF-J) system -orthogonal to the regional fold axes- consisting of the CF-J1 set trending NW/SE (315&amp;plusmn;5&amp;deg;), and a subordinate Longitudinal Joint System (L-J) -subparallel to the fold axes- consisting of a NE-SW L-j1 set, an ENE-WSW (60&amp;deg;&amp;plusmn;5&amp;deg;) L-j2 set, and an E-W trending L-j3 set. Fracture patterns show intensity and density ranging from 11.2395- 53.3443 m-1 and 85.2747- 629.5928 m-2 respectively. Joints in the NE-SW show high dilation and low slip tendencies given a NW-SE directed maximum principal horizontal stress &amp;sigma;H stress field. The units of the Abakaliki Formation show better connectivity and lower permeability anisotropy as both fracture systems are well developed in those units. These joints, having formed in the period leading up to the Santonian inversion would have been ideal conduits for migration and flow of hydrocarbon and mineral fluids. The Cross-Fold System precedes the folding episode in the Santonian period and is likely a result of overpressure conditions due to disequilibrium compaction in the Albian- Turonian strata in an initial compressive regional tectonic stress field. The Longitudinal System formed later and is related to the outer-arc flexure of the folded units taking advantage of the nascent cleavage structures in the folded shale units.

Unconventional Petroleum Sedimentology: A Key to Understanding Unconventional Hydrocarbon Accumulation

The commercial exploitation of unconventional petroleum resources (e.g., shale oil/gas and tight oil/gas) has drastically changed the global energy structure within the past two decades. Sweet-spot intervals (areas), the most prolific unconventional hydrocarbon resources, generally consist of extraordinarily high organic matter (EHOM) deposits or closely associated sandstones/carbonate rocks. The formation of sweet-spot intervals (areas) is fundamentally controlled by their depositional and subsequent diagenetic settings, which result from the coupled sedimentation of global or regional geological events, such as tectonic activity, sea level (lake level) fluctuations, climate change, bottom water anoxia, volcanic activity, biotic mass extinction or radiation, and gravity flows during a certain geological period. Black shales with EHOM content and their associated high-quality reservoir rocks deposited by the coupling of major geological events provide not only a prerequisite for massive hydrocarbon generation but also abundant hydrocarbon storage space. The Ordovician–Silurian Wufeng–Longmaxi shale of the Sichuan Basin, Devonian Marcellus shale of the Appalachian Basin, Devonian–Carboniferous Bakken Formation of the Williston Basin, and Triassic Yanchang Formation of the Ordos Basin are four typical unconventional hydrocarbon systems selected as case studies herein. In each case, the formation of sweet-spot intervals for unconventional hydrocarbon resources was controlled by the coupled sedimentation of different global or regional geological events, collectively resulting in a favorable environment for the production, preservation, and accumulation of organic matter, as well as for the generation, migration, accumulation, and exploitation of hydrocarbons. Unconventional petroleum sedimentology, which focuses on coupled sedimentation during dramatic environmental changes driven by major geological events, is key to improve the understanding of the formation and distribution of sweet-spot intervals (areas) in unconventional petroleum systems.

Effects of confining pressure and microscale heterogeneity on hydrocarbon retention and pore evolution from artificial maturation of Eagle Ford Shale

Although shale heterogeneity has recently emerged as a key topic in unconventional petroleum systems, hydrocarbon (HC) retention and pore evolution in organic-rich shales still remain poorly constrained. In this study, an organic-rich Eagle Ford Shale sample (EqVRo = 0.92%) from a shale-oil prospecting well in South Texas was selected for gold-tube pyrolysis experiments to investigate organic matter (OM) -hosted pore development versus confining pressure during thermal maturation. Before heating, the OM-type heterogeneity and associated pore characteristics in the sample were examined by thin section and scanning electron microscopy imaging, combined with elemental mapping by X-ray energy-dispersive spectroscopy. Four forms of OM occurrence that are closely associated with different mineral matrix domains are distinguished, including the ductile oil-bearing primary OM and rigid primary OM in the siliceous-argillaceous seams, as well as the secondary OM in coccolith-rich lenses and in foraminifera chambers. From heating experiments, the pressure effect on pore evolution was found to be pronounced for the secondary OM in the foraminifera chambers, in which the coalescence of small pores to larger pores upon OM maturation was accelerated by increasing fluid pressure, accompanied by arrangement and densification of OM structures. However, the expulsion effect as a function of confining pressure seems to be evident only for the secondary OM in the coccolith-rich lenses. In contrast, the two types of primary OM in the siliceous-argillaceous seams do not show any apparent changes in pore development over the investigated pressure range of 10 to 120 MPa, probably due to stiffer mechanical properties of primary OM as compared to secondary OM. The discrepancies in pore evolution of different OM types as a response to the variation in confining pressure upon maturation primarily depend on the physical-chemical properties of these various OM materials.Of further importance, observed differences in OM evolution and associated pore characteristics in response to the variation in confining pressure imply that the microscale heterogeneity of shale fabric controls the extent of oil retention and pore evolution. In contrast to the intragranular pores in the foraminifera chambers, the intergranular pores in the coccolith-rich lenses from the Eagle Ford Shale sample are relatively smaller, yet more likely interconnected. Thus, these coccolith-associated pores may provide not only significant storage space but also a major flow pathway for HC production. Our investigation at the microscopic scale provides concepts indicating that HC retention and OM-hosted pore evolution occur differently in two contrasting types of mineral matrix pores, which is critical to successful unconventional shale oil and gas exploration in sedimentary basins.

Geochemical evidence for the internal migration of gas condensate in a major unconventional tight petroleum system

Unconventional petroleum systems go through multiple episodes of internal hydrocarbon migration in response to evolving temperature and pressure conditions during burial and uplift. Migrated fluid signatures can be recognized using stable carbon isotope and PVT compositional data from produced samples representative of in-situ petroleum fluids. Such samples, however, are seldom collected due to operational complexity and high cost. Here, we use carbon isotope and PVT data from co-produced hydrocarbon gas and liquid to provide evidence for widespread migration of gas-condensate in the Montney unconventional petroleum system of western Canada. Extended C1–C33 isotopic profiles exhibit convex upward signatures with C4–C5 maxima at low molecular weight, and increasing or nearly uniform signatures at high molecular weight. Additionally, recombination PVT compositional data show C6–C15 condensate concentrations are higher than expected for unmodified oils. The combined convex upward and increasing or uniform isotopic signatures are interpreted as mixing profiles formed by the introduction of high-maturity gas-condensate (C1–C15) to shallower zones with in-situ hydrocarbon fluids of lower thermal maturity. The recognition of widespread gas-condensate migration adds to the complex history of internal hydrocarbon migration within the Montney tight-petroleum system including previously identified migration episodes of early oil and late-stage methane-rich gas.

Predicting marine organic-rich deposits using forward stratigraphic modelling: The Jurassic Najmah source rock – Case study

Predicting the distribution and heterogeneity of marine Mesozoic organic-rich rocks is a challenging task that requires multi-disciplinary data integration supported by innovative numerical modelling. This study aims at investigating the factors controlling marine organic matter production, accumulation, and preservation along the eastern Arabian intrashelf basins. Such types of basins exhibit an enhanced lateral and vertical facies variability caused by the interplay between shallow and deeper water sedimentation. The work focuses on characterizing the Mid-Upper Jurassic Najmah Formation that presents source rock, reservoir, as well as seal characteristics along Kuwait. It comprises high maturity levels (>0.6% Ro) and TOC values ranging between 2 and 30%. Forward stratigraphic modelling that includes organic matter production, transport, and preservation (i.e., degradation and dilution) was utilized. Models corresponding to two end-member basin types (restricted and fully open marine) have been simulated to mimic the organic matter deposition within a 3rd-order sequence stratigraphic framework. Simulation outputs provide a qualitative and quantitative assessment of organic matter characteristics (TOC, HI, and OI) at the time of deposition. Results show that (1) a combined variable eustatic sea level change and tectonic subsidence are the main driving mechanisms for sediment accommodation during the Mid-Upper Jurassic time, (2) strong anoxic conditions in the restricted basin simulations promote the preservation of organic-rich deposits in the distal northern sectors while (3) the influence of open marine bottom current oxygenation is not expected to impact the relatively shallower conditions affecting the intrashelf basin (<200 m depth), (4) organic matter dilution can be observed along the southernmost sectors of Kuwait due to high sedimentation rates related to the development of gravity driven deposits. Sensitivity analysis on input parameters (i.e., primary productivity vs water depth) supports the partially restricted basin conditions with occasional connection to the open ocean during eustatic sea level rise. This study contributes to the improvement of basin models in conventional as well as unconventional petroleum system exploration.

Geochemical evaluation of produced petroleum from the Middle Permian Lucaogou reservoirs Junggar Basin and its implication for the unconventional shale oil play

The shale of the Middle Permian Lucaogou Formation in the Jimusaer Sag has become one of the most important prospects for unconventional shale oil production in China. The Lucaogou Formation develops two sweet spots, the upper (P2l22) and lower (P2l12) sweet spots, which are not more than 150 m apart. Interestingly, oils produced from the lower sweet spots have higher densities and viscosities than those in the upper sweet spots. Meanwhile, these high-viscosity oils have brought technical challenges to shale oil production. In this paper, geochemical data from 78 source rock solvent extracts and 17 oil samples from various depths were employed to elucidate unconventional petroleum systems and the reason for high viscosities. The source rocks of the Lucaogou Formation are good to excellent, primarily type II and II-III kerogens, and are now in the early-peak oil window. Oils produced from the P2l12 interval are characterized by abundant polar compounds, which are derived from the P2l12 and P2l11 intervals source rocks with relatively high marine sources contribution. Oils in the P2l22 interval are generated from the P2l22 interval source rocks with relatively high terrigenous-marine sources contribution. Terpane biomarker ratios indicate all oil samples are derived from lacustrine source rocks. The distributions of terpanes and steranes in these samples are similar, with high quantities of C29 steranes and low amounts of diasteranes. Migration from sources to reservoirs in the Lucaogou shale oil systems is short-distance given thermal maturity considerations. All oil samples have experienced slight biodegradation (PM level 1–2) at most. The sources and thermal maturities are the primary reasons for the high viscosities of the crude oils produced from the P2l12 interval. This research also indicates the Lucaogou shale petroleum system could be divided into two subsystems, and the production of different unconventional petroleum subsystems requires different strategies.

In-situ SEM characteristics of dispersed organic matter in continental shale with its implication for dessert evaluation--A case study of Paleogene shale in the Cangdong Sag, Bohai Bay Basin, China

Organic matter (OM) in continental shale serves as both the source of oil and gas and the storage space in unconventional petroleum systems. However, directly identifying the types of organic matter under SEM is challenging when simultaneously observing minerals and pores. Kong2 Member(E2k2) of Paleogene in Cangdong sag of Bohai Bay basin is a typical continental shale oil layer in China. Based on the positioning observation technology combining field emission scanning electron microscope (FE-SEM) and fluorescence microscope, the in-situ SEM identification and observation of macerals were carried out, and the identification methods and characteristics of organic macerals were summarized. The results show that: (1) Organic macerals in E2k2 shale are divided into vitrinite, inertinite, liptinite and solid bitumen by external morphology, hardness, brightness, color, protrusion, pore and fracture development of organic matter, and further subdivided into multiple subcategories. Based on the SEM charging effect of the remaining oil, it is further confirmed that the shale movable oil and oil generation potential developed by lipoid group is the largest, while the shale movable oil and oil generation potential developed by vitrinite group and inertinite group is the worst; (2) The organic pores include primary pores and secondary pores. The pores of primary organic matter are derived from the biological structure of primary organic matter, and the secondary organic pores are developed during the thermal maturation of oily organic matter. Clay mineral catalysis, difference of hydrocarbon generation potential and residual pores of primary organic matter control the development of organic pores; (3) Calcareous-dolomitic shale and felsic shale are typical lithology formed in relatively dry and humid climate respectively, and the types of organic macerals are significantly different. Although the former has weak total hydrocarbon generation, it has stronger oil generation potential and is worthy of attention in dessert prediction and exploration.

Geochemical Considerations from the Carboniferous Unconventional Petroleum System of SW Iberia

The Baixo Alentejo Flysch Group (BAFG) is an important stratigraphic unit that covers over half of the South Portuguese Zone (SPZ) depositional area, and it is composed by three main tectono-stratigraphic units: the Mértola, Mira, and Brejeira formations. All of these formations contain significant thicknesses of black shales and have several wide areas with 0.81 wt.%, 0.91 wt.%, and 0.72 wt.% average total organic carbon (TOC) (respectively) and thermal maturation values within gas zones (overmature). This paper is considering new data from classical methods of organic geochemistry characterization, such as TOC, Rock–Eval pyrolysis, and organic petrography, to evaluate the unconventional petroleum system from the SPZ. A total of 53 samples were collected. From the stratigraphical point of view, TOC values seem to have a random distribution. The Rock–Eval parameters point out high thermal maturation compatible with gas window (overmature zone). The samples are dominated by gas-prone extremely hydrogen-depleted type III/IV kerogen, which no longer has the potential to generate and expel hydrocarbons. The petrographic analyses positioned the thermal evolution of these samples into the end of catagenesis to metagenesis (wet to dry gas zone), with values predominantly higher than 2 %Ro (dry gas zone). The presence of thermogenic hydrocarbon fluids characterized by previous papers indicate that the BAFG from SPZ represents a senile unconventional petroleum system, working nowadays basically as a gas reservoir.

A method for automatic shale porosity quantification using an Edge-Threshold Automatic Processing (ETAP) technique

Scanning electron microscopy (SEM) is one of the most prevalent methods used to image and quantify the pore size distribution of shale rock, critical in understanding unconventional petroleum systems and production. Generally, digital greyscale SEM images of shale are currently processed for pore quantification either by a manual drawing method, manual threshold method, automatic threshold method, edge detection or watershed methods, all of which have some limitations that impact the quality of pore extraction results. A new, Edge-Threshold Automatic Processing (ETAP) method is reported here to enable robust extraction and quantification of pore data in shale images. Image pre-treatment makes the greyscale of regions brighter than that of kerogen set to the peak value of kerogen greyscale. The pore image is subsequently obtained using an edge detection method. A discriminant function has been designed to determine the best threshold of the greyscale image to obtain the pore image. Finally, combination of both processed pore images gives the final pore image. Our new method overcomes the impact of kerogen, mineral, roughness and artificial debris caused by pre-treatment of samples, which potentially introduce errors using alternative methods. We compare our new method to a systematic manual drawing method. The processing results through ETAP provide reliable results, and gets the highest value of 0.7466 using a discriminant function Qt, compared with the automatic threshold methods, the edge detection method and watershed method. The application of the ETAP method on shale samples of the Longmaxi Formation and Qiongzhusi Formatiosn in Sichuan basin shows that samples from the Longmaxi Formation have more organic pores than that of the Qiongzhusi Formation, however a larger size of inorganic pores develop in the Qiongzhusi shale. This indicates that shale of the Longmaxi Formation has better reservoir properties and reliable preservation conditions.

Unravelling the impact of lithofacies on the composition of NSO compounds in residual and expelled fluids of the Barnett, Niobrara and Posidonia formations

The influence of lithofacies on the composition of NSO (nitrogen-, sulfur- and oxygen- containing) compounds in unconventional petroleum systems has been investigated using examples of biogenic carbonate-rich Niobrara Shale, biogenic quartz-rich Barnett Shale and detrital clay-rich Posidonia Shale. The chosen sample sets all contain Type II marine kerogen in the peak–late oil window. Solvent extracts were analyzed using Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR-MS), combined with atmospheric pressure photoionization in positive ion mode ((+)-APPI) and electrospray ionization in negative ion mode ((−)-ESI). Covering source and reservoir units, our study furthermore enables tracing the impact of lithofacies on primary petroleum migration within the Niobrara and Barnett shales.Siliciclastic Barnett and Posidonia shale extracts reveal higher proportions of NSO compounds confirming their generally higher retention capacities for polar organic compounds. However, different retention specificities of biogenic quartz- and clay-rich rocks are indicated by varying NSO compound compositions in their bitumen fraction: biogenic quartz preferentially preserves and retains organonitrogen compounds, while the more polar acidic organooxygen species are preferably retained by clay minerals. Extracts from the carbonate rocks contain a larger fraction of nonaromatic cyclic sulfoxides and amides that are likely formed by oxidation processes during maturation of organic matter.Fractionations induced by the intra-formation migration differ between the Barnett and Niobrara sample sets. While low-polarity organonitrogen species are retained in both Barnett (to a greater extent) and Niobrara source units, a preferential migration of highly alkylated and small acidic NSO components out of the source is only observed in the Niobrara samples.

Big Data Guided Unconventional Digital Reservoir Energy Ecosystem and its Knowledge Management

Abstract Background: In shale basins, petroleum systems are complex; they hold data sources in Big Data scales. The motivation of research lies with the facts of exploring effective inherent connectivity between unconventional petroleum systems. The connectivity between energy reservoir systems is ambiguous within a distinctive petroleum ecosystem. Heterogeneity and multidimensionality of unstructured data sources are additional challenges, precluding systematic modelling of diverse petroleum systems and their data integration process, including growing demand for storage systems. The research aims to establish the knowledge-based connectivity between petroleum systems through Information System (IS) articulations, visual analytics and data management. Method: We investigate the knowledge-based IS guided exploration and production systems to explore the connectivity between diverse unconventional petroleum systems and forecast the reservoir energy. We articulate Design Science Information System (DSIS), bring various IS artefacts, unify multiple domains of petroleum provinces and analyze the associativity between petroleum systems. In addition, use, reuse, effectiveness and interoperability are utility properties of IS artefacts that we evaluate. We implement IS solutions in the oil and gas industries to facilitate database management and reservoir energy exploration. Results: We simulate DSIS as an Unconventional Digital Petroleum Ecosystem (UDPE) as it allows us to investigate and ascertain the interplay between petroleum systems’ elements and processes. Metadata cubes are computed for data views to visualize, interpret, and implement IS articulations in energy systems. We compute the structure and reservoir attribute views for interpreting energy-driven petroleum systems, prospect evaluation and business-knowledge management with a viable DSIS solution. Conclusions: The DSIS emerges as a knowledge-based digital ecosystem innovation, demonstrating how it can effectively interconnect geographically controlled petroleum systems. Its development, in the exploration of unconventional shale basins, is a knowledge-based reservoir-energy management solution. This research is beneficial to IS practitioners who wish to pursue energy research in reservoir ecosystem contexts.

Geology still matters – Unconventional petroleum system disappointments and failures

Machine learning and factory drilling approaches have increased efficiency and improved the commerciality in many tight plays. However, not all the original resource estimates and potential opportunities have, been confirmed by the drill-bit. Although some of the commercial disappointments have been a result of policy decisions, more often they are due to partial or complete failure of the unconventional petroleum system and/or the hydrocarbon phase encountered. Studies have demonstrated that not all mudrocks are organic-rich, contain the appropriate kerogen type, have achieved the appropriate level of thermal maturity, have suitable unconventional reservoir properties, are able to retain hydrocarbons, or have the necessary resource density to be a viable tight rock target. An overview of six shale plays in this study (the Longmaxi Shale of China, the Silurian shales of eastern Europe, the Cambay Shale of India, the Barnett Shale in northeast Texas, the Eagle Ford Shale of South Texas, and the Waltman Shale of Wyoming) represent the diversity of potential geologic problems. It becomes apparent that, just as in the case of conventional exploration, successful unconventional exploration and development requires a full assessment of the petroleum system. Absence or limited effectiveness of one or more elements (i.e., source rock presence, quality, and thermal maturity, reservoir presence and quality, and retention) of the petroleum system is a primary driver for mismatch between resource expectations and results. • Exploration and exploitation of shale systems requires an understanding of all petroleum system elements. • Many of the exploration failures in shale systems could have been predicted prior to drilling. • Common causes of failure are wrong kerogen type and inappropriate level of thermal maturity. • Reservoir quality appears to be more associated with the ability to fracture than in inherent porosity and permeability.

Exploring for the Future geomechanics: breaking down barriers to exploration

Exploring for the Future (EFTF) is an Australian Government initiative focused on gathering new data and information about potential mineral, energy and groundwater resources across Australia. The energy component of EFTF, initially focussed on northern Australia, aims to improve our understanding of the petroleum potential of frontier Australian basins. Building an understanding of geomechanical rock properties is key to understanding both conventional and unconventional petroleum systems as well as carbon storage and sedimentary geothermal systems. Under EFTF, Geoscience Australia has undertaken geomechanical work including stress modelling, shale brittleness studies and the acquisition of new rock property data through extensive testing on samples from the Paleo- to Mesoproterozoic South Nicholson region of Queensland and the Northern Territory, and the Paleozoic Kidson Sub-basin of Western Australia. Work in these regions demonstrates regional stress orientations in broad agreement with previously modelled, continent-scale stress orientations and stress magnitudes that vary through the basin with depth and by lithology. Rock testing highlights potentially brittle shales and demonstrates variable rock properties in line with lithology. These analyses are summarised herein. Providing baseline geomechanical data in frontier basins is essential as legacy data coverage can often be inadequate for making investment decisions, particularly where unconventional plays are a primary exploration target. As EFTF increases in scope, Geoscience Australia anticipates expanding these studies to encompass further underexplored regions throughout Australia, lowering the barrier to entry and encouraging greenfield exploration.

Coupled stratigraphic and petroleum system modeling: Examples from the Ordos Basin, China

With the emergence of the “continuous petroleum accumulations” concept and unconventional petroleum exploration, the traditional source-to-trap petroleum system model becomes vague spatially because the source, reservoir, and seal may intermingle within the same stratigraphic unit. In such a system, the spatial distribution of key petroleum system elements therefore depends on sedimentary facies heterogeneities. Available basin modeling programs lack built-in sedimentary infill modeling capabilities to populate heterogeneities within the traditional “layer-cake” modeling framework where source, reservoir, and seal units are commonly represented as discrete and homogeneous layers. To address such a challenge, and to model both conventional and unconventional petroleum systems holistically in a single simulation, we coupled stratigraphic forward modeling with basin modeling, where the former provides a detailed three-dimensional sedimentary facies volume with finer-scale heterogeneities effectively captured as input for the latter. The forward stratigraphic model we used in our study is a hydrodynamics-based program, which is able to model clastic, carbonate, and organic deposition with spatial resolutions from centimeters to meters vertically and hundreds of meters to tens of kilometers horizontally. The Triassic tight (sandstone) oil plays and the upper Paleozoic tight (sandstone) gas plays from the Ordos Basin, central China, were modeled using the integrated approach. Compared to the conventional layer-cake models, the coupled stratigraphic forward modeling and basin modeling produced much more realistic results in terms of the quantity of petroleum accumulation and their spatial distributions.

Fracture behavior of Longmaxi shale with implications for subsurface applications

Fracture mechanical properties of shales have gained continued interest recently due to their critical role in many shale-related applications such as unconventional petroleum systems and subsurface carbon and waste disposal. However, due to their strong reactive nature to fluids, fracture mechanical properties of shales have not been extensively studied like other rock types. A more comprehensive understanding of fracture system development in shales under reactive fluids is needed for subsurface applications. We have measured fracture mechanical properties of Longmaxi shale outcrop samples in the Sichuan Basin, China, under different environments of ambient air, deionized water, saline fluids of NaCl and KCl at 0.5 M concentration, and acidic HCl fluid at pH of 5. All aqueous fluids tested show strong weakening effects on fracture propagation compared to the air environment, with the fracture toughness reduced by 75% and the subcritical fracture growth index reduced by 50%. Microstructural analysis reveals the predominantly grain boundary opening cracking mode for all tests, but the fracture traces branch more in reactive aqueous fluids. Natural fractures are comparable with artificial fractures in morphology. Bedding-perpendicular opening mode fractures with multiple-stage fracture fillings of calcite, quartz, and organic matters develop well in natural fractures. Our results suggest that clay mineral hydration and expansion are the main cause for the fluid weakening effect in Longmaxi shale, which has substantial implications for subsurface shale failure processes.