Unconventional Source Rock Research Articles

Determine Oil and Water Saturations in Preserved Source Rocks From 2D T1-T2 NMR

Two-dimensional (2D) T1-T2 NMR has been widely proposed as a method to determine the fluids present in unconventional source rocks. However, the assignment of the components in the 2D T1- T2 NMR spectra has so far been based on conceptual consideration and lacks rigorous experimental verification. Many assignment variations appeared in the literature and can be misleading. For example, large T1/T2 peaks in the 2D T1-T2 NMR were suggested to be fluid in small pores coupled with kerogen solid through dipolar relaxation. Our recent 500-MHz NMR relaxation experiments found that the dipolar relaxation between nanoconfined fluids and solid matrix is not big enough to support that large T1/T2 interpretation. The objective of this paper is to determine what quantitative data can be obtained using 2D T1-T2 NMR from source rocks with high confidence. We found the oil and water saturation can be accurately measured in preserved source rock plugs. Two-dimensional T1-T2 NMR data were collected on preserved core plugs from five wells of a source rock reservoir using an inversion-recovery Carr-Purcell-Meiboom-Gill (CMPG) pulse sequence on a 12-MHz NMR instrument. The acquired 2D data were inverted using an optimized inversion software, MUPen2D. We then obtain oil and water content in the plug from the 2D T1-T2 NMR using an in-house-developed NMR MATLAB app. The porosity of all the plugs was measured using a combined NMR and gas porosimetry (CNG) method. Oil and water saturation were also obtained using an industry-standard method developed by the Gas Research Institute (GRI) on the rock material close to where the plug was drilled. The oil and water saturations measured on the preserved plugs using 2D T1-T2 NMR and CNG are consistent with those from the GRI method using crushed rocks and an invasive cleaning procedure. The results show that oil and water saturations were accurately determined from 2D T1-T2 NMR on preserved source rock samples with high confidence. The NMR method is nondestructive and noninvasive and takes less than 4 hours on a preserved source rock plug, while GRI is destructive and invasive and can take several weeks for an accurate measurement on one sample. The measured results can be further used to determine the production potential of a source rock well in combination with log data.

Oxidative Hydraulic Fracturing Fluid to Enhance Production from Source Rock Reservoirs

Summary The steep production declines generally observed after hydraulic fracturing in unconventional source rock reservoirs has been attributed to several potential causes. Recently, a new additive to the stimulation fluid system was proposed to extend economical longer-term production from these formations. Oxidizer-laden fracturing fluid systems are shown to create cracks and deep channels within the organic matter present in the source rock, such as kerogen, thereby increasing the source rock permeability and enhancing the hydraulic conductivity of the exposed fracture faces. To this end, the fluid design and recommendations for its application are illustrated herein. Oxidants composed of oxychlorine (ClOn−) and oxybromine (BrOn–) (where n = 0 to 4) are effective for kerogen depolymerization or degradation at depth. This study illustrates the beneficial effects of two specific oxidizers—sodium chlorite (NaClO2) and sodium bromate (NaBrO3)—on kerogen-rich source rock subjected to in-situ reservoir conditions. Source rock samples were cut and polished to test the oxidizer’s impact on the organic and inorganic regions. Scanning electron microscopy (SEM) and energy dispersive X-ray spectroscopy (EDS) were performed on the rock surface to identify specific organic matter features. The samples were then chemically treated with varying conditions of NaClO2 or NaBrO3 (concentration range: 0.013–0.054 M; temperature: 150°C; and time: 3–24 hours). Samples were returned to the scanning electron microscope for post-treatment analysis. Furthermore, the oxidants were packaged within a slickwater hydraulic fracturing fluid system for field application, and their effects on viscosity and friction reduction were also studied. SEM images and EDS maps of kerogen-rich rock samples observed before and after treatment with oxidizing fluid showed a series of cracks formed throughout the organic matter domains, where increasing the concentration of oxidizer in the treatment fluid showed a clear increase in the prevalence of cracks throughout the surface. The effect of time was also observed, as short treatment times resulted in porosity/permeability creation in the kerogen, though longer treatment times were associated with more severe degradation. Optimal conditions for NaClO2 and NaBrO3 concentrations in the additive fluid systems were different and will be herein highlighted. Each oxidizer (10–20 pptg concentration) was added to slickwater with variable friction reducer concentration (1 gpt, 2 gpt, and 4 gpt), and shear sweeps performed at both 70°F and 180°F. A negligible difference is observed between the viscosities of the base fluid and the fluid with either oxidant at low friction reducer concentration. Meanwhile, flow loop tests demonstrated that the oxidizer did not affect the friction reducer except to slightly boost the performance due to the salt effect on the polymer. Two strong oxidants, available as commodity chemicals, are shown to be effective in cracking kerogen and any present organic matter, thus creating permeable channels and enhancing the overall permeability of the exposed source rock fracture faces. Meanwhile, the proposed fracturing fluid additives display good compatibility with other slickwater fluid components, demonstrating the potential for universal usage in unconventional stimulations. The recommendations for its application as a fluid additive in slickwater are herein illustrated.

Organic Matter Accumulation in the Upper Permian Dalong Formation from the Lower Yangtze Region, South China

AbstractThe Late Permian was marked by a series of important geological events and widespread organic‐rich black shale depositions, acting as important unconventional hydrocarbon source rocks. However, the mechanism of organic matter (OM) enrichment throughout this period is still controversial. Based on geochemical data, the marine redox conditions, paleogeographic and hydrographic environment, primary productivity, volcanism, and terrigenous input during the Late Permian in the Lower Yangtze region have been studied from the Putaoling section, Chaohu, to provide new insights into OM accumulation. Five Phases are distinguished based on the TOC and environmental variations. In Phase I, anoxic conditions driven by water restriction enhanced OM preservation. In Phase II, euxinic and cycling hydrological environments were the two most substantial controlling factors for the massive OM deposition. During Phase III, intensified terrestrial input potentially diluted the OM in sediment and the presence of oxygen in bottom water weakened the preservation condition. Phase IV was characterized by a relatively higher abundance of mercury (Hg) and TOC (peak at 16.98 wt%), indicating that enhanced volcanism potentially stimulated higher productivity and a euxinic environment. In Phase V, extremely lean OM was preserved as a result of terrestrial dilutions and decreasing primary productivity. Phases I, II and IV are characterized as the most prominent OM‐rich zones due to the effective interactions of the controlling factors, namely paleogeographic, hydrographic environment, volcanism, and redox conditions.

Transport and depositional processes of organic matter evaluated by biomarker profiles in Miocene turbiditic sequences from Hokkaido, Japan

Extrabasinal turbidity currents, also known as hyperpycnal flows, can deposit vast amounts of organic carbon to the marine realm. On the other hand, intrabasinal turbidity currents are commonly thought to resuspend and further oxidize organic matter (OM), creating deposits with poor preservation of terrestrial OM. However, recent studies have shown that intrabasinal turbidity currents can still preserve terrigenous OM after reworking previously deposited OM-rich sediments. As such, both types of turbidity currents may act as unconventional source rocks. Considering that there is a discrepancy between global carbon burial fluxes in the marine environment and the amount of organic carbon delivered by rivers, OM preservation within such sandy deposits should not be overlooked. We investigated both plant fragment-rich extrabasinal and intrabasinal turbidites of the Miocene Kawabata Formation (Hokkaido, Japan) by using biomarker distributions within different facies formed by changes in sediment concentration due to progressive deposition during waning flow. Clear distinctions in terms of sedimentological features and organic geochemical characteristics between different facies were found and are interpreted to be caused by different OM sources and sedimentological processes. The sandy extrabasinal turbidites have high amounts of organic carbon, high pristane/phytane ratios, and fewer amounts of marine algal biomarkers due to direct transport from the terrestrial environment without mixing with marine waters. Intrabasinal, Bouma-type turbidites generally have poor OM, and low pristane/phytane values but high concentrations of algal biomarkers since sediments are sourced from the marine environment. In both extrabasinal and intrabasinal turbidites of this study, the plant fragment-rich sandy layers deposited by flows with lower sediment concentrations preserve high amounts of terrigenous OM, possibly due to having densities allowing woody plant fragments to remain within the flow and corresponding deposit, while basal Ta sandstones and Te hemipelagic deposits contain more marine OM due to erosion plus incorporation of marine sediments and mixing with marine waters respectively. Mud clasts formed in basal flows such as surge-like intrabasinal turbidity currents may also enhance OM preservation in plant fragment-poor sandstones.

Role of zooclasts in the kerogen type and hydrocarbon potential of the lower Paleozoic Alum Shale

This study investigates the role of zooclasts in the bulk organic matter composition, kerogen type, and hydrocarbon generation potential of the lower Paleozoic marine Alum shale in Baltoscandia, northwestern Europe. The results show that graptolite periderm is composed of non-granular cuticles and granular filling. The graptolite cuticle is non-fluorescing and has a well-polishing measurable surface, while the graptolite granular fraction is semi-translucent and has brownish fluorescence, suggesting remaining hydrocarbon generation potential. The graptolite granular fraction shows similar optical characteristics to fluorescing diagenetic solid bitumen. Both the graptolite granular fraction and diagenetic solid bitumen have low intensity yellow to brown fluorescence and contribute to generative potential (Rock-Eval S2). The sum of semi-quantitative zooclastic cuticle (non-granular graptolite cuticle, chitinozoan cuticle, and vitrinite-like) and diagenetic solid bitumen content, obtained from maceral point-counting, correlates with the non-generative organic carbon content. Enrichment of zooclastic cuticle in the samples is displayed as enrichment of inert organic carbon, and hence bulk geochemical kerogen of type III. This refractory carbon-rich maceral enrichment results represents autochthonous ‘refractory organic carbon dilution’ and will lead to Hydrocarbon Index (HI) underestimation. Confined hydrous pyrolysis was used to compare the hydrocarbon generation process of a zooclastic cuticle-lean sample (0.2 vol%) and a zooclastic cuticle-rich (1.6 vol%) sample. Results indicate that there are four stages of hydrocarbon generation in the artificial maturation of unconventional source rock of the Alum Shale. The zooclastic cuticle-lean sample has higher hydrocarbon generation potential and more oil-prone than the zooclastic cuticle-rich sample, which is gas-prone and generates more CO2. This difference in hydrocarbon generation is attributed to differences in the organic constituent composition.

Chemomechanical effects of oxidizer‐CO2 systems upon hydraulically fractured unconventional source rock

AbstractCarbon dioxide (CO2) as supercritical (scCO2) or foamed (CO2‐Foam) fluid has been tested many times as a fracturing fluid, though it has not yet proven viable. Many challenges have been identified with scCO2 as a fracturing fluid, including poor additive solubility, low viscosity, and limited accessibility. However, CO2 is known to adsorb to organic matter (OM) and displace methane (i.e., enhanced coal bed methane [ECBM] operations), or to mobilize oil as in tertiary enhanced oil recovery. In this study we augment the efficacy of the kerogen control fluid (KCF) for stimulating unconventional rock formations by alternating aqueous oxidizing fracturing fluid with CO2 injection or by combining oxidizers directly with CO2 as a new additive. To this end, KCF‐CO2 tests were designed to treat OM and extend the depth of permeability enhancement. We report the first attempt to combine oxidizer with CO2 in the presence of source shale rocks at elevated temperature and pressure. Scanning electron microscopy imaging of the treated shale sample surfaces demonstrate potential porosity and permeability enhancement, though some mineral and organic deposits are also observed, which may prove to be detrimental. Meanwhile, alternating water‐based KCF with CO2 provides a potential improvement to the KCF as predicted by early lab results on OM. The KCF‐CO2 concept has no equivalent to date in unconventional hydraulic fracturing operations. This technology will contribute to reducing the footprint of anthropogenic CO2 and enhancing its permanent sequestration in unconventional stimulated reservoirs, compliant with our global clean energy initiative of carbon capture, utilization, and storage.

Brittleness evaluation of Naparima Hill mudstones

The brittleness of unconventional source rock reservoirs is an essential parameter that controls the effectiveness of hydraulic fracturing operation. Brittleness can vary with effective pressure (equivalent to burial depth) and can be influenced by fluid saturation. Therefore, a detailed evaluation of rock brittleness is necessary prior to field applications. The late Cretaceous Naparima Hill Formation is the primary source for most of the 4 billion barrels of oil and 10 trillion cubic feet of gas produced in the last hundred years from conventional reservoirs in Trinidad, West Indies. This Formation is now being considered an unconventional reservoir in order to prolong and increase current productions. However, despite being a prolific Formation, there are no available geomechanical data, including brittleness. Brittleness index (BI) is often used to measure rock brittleness. In this study, we determined elastic-based BI from P- and S-wave velocity measurements, at effective pressures up to 130 MPa, for dry and water saturated outcrop mudstones from four lithofacies within the Naparima Hill Formation. The experimental results show that the BI for all four lithofacies, is independent of effective pressures in both dry and water saturated conditions. All four lithofacies can be considered brittle under dry conditions. However, when saturated, the BI reduces, which proves significant for softer lithofacies (siliceous calcareous mudstones and siliceous mudstones). In this saturated state, the harder lithofacies (calcareous mudstone interbedded with black chert and carbonate rich mudstone with nodular chert) are considered marginally brittle and the softer ones, are considered ductile. The results highlight that porosity is the main factor that controls the magnitude of reduction in the BI when the mudstones are fully saturated.

Source rock properties and pore structural framework of the gas-prone Lower Permian shales in the Jharia basin, India

This paper examines the source rock potential and pore structural framework of Lower Permian shales belonging to Barren Measures and Barakar Formations of Jharia basin, eastern India. The Jharia basin contains prolific coking-coal reserves and, consequently, the organic-matter in this basin tends to be mature. Open system pyrolysis analysis reveals that the Barakar Formation shales are thermally more mature and organic-rich than the Barren Measures Formation. Analysis reveals that shales of the Barren Measures possess “fair” to “good” oil generation potential. The more mature shales of the Barakar Formation are gas prone. Detailed pore scale distribution and fractal metrics determined by low-pressure N2 gas adsorption are observed to be higher for the Barren Measures Formation than the more mature and organically rich Barakar Formation shales possibly due to the inability of N2 gas to access the ultrafine components of the complex pores in the Barakar Formation shales. Substantial concentration of pores, organic-rich character, and thermal maturity levels indicates that the studied horizons have unconventional source rock properties.

New palynostratigraphic data of the Irati (Assistência Member) and the Corumbataí formations, Paraná Basin, Brazil, and correlation with other south American basins

This research presents the palynostratigraphy of organic-rich shales from the Irati and the Corumbataí formations, Paraná Basin (PB), Southeastern Brazil, as part of an unconventional hydrocarbon source rock and CO2 reservoir assessment study. Thirty-four samples from the Corumbataí Formation and the Assistência Member of the Irati Formation were collected in the states of Goiás (northern border of the PB), São Paulo and Paraná (eastern and southern border of the PB, respectively). The acquired data allowed to establish a comprehensive palynostratigraphic study across the basin where a total of 18 pollen genera (34 pollen species), seven spore genera, four microplankton genera (1 species), and Chlorophyceae algae species where identified. The palynostratigraphic analysis also reveals a clear dominance of bisaccate pollen grains such as Corisaccites alutas, Lueckisporites virkkiae, and Weylandites lucifer. The Lueckisporites virkkiae zone was identified in the upper part of the Irati Formation (Assistência Member) and the lowermost part of the Corumbataí Formation, indicating a Kungurian to Roadian age for this part of the succession. Differences in the Guttulapollenites hannonicus and Tornopollenites toreutos biostratigraphic ranges, recovered in the Corumbataí Formation, suggest an earlier development of these species in the Paraná Basin during the middle Permian. Therefore, to evaluate the differences in the first occurrences of key species within the Paraná Basin, a close palynostratigraphic correlation between the main Guadalupian-Lopingian South American Gondwana basins is tentatively established.

Pore anisotropy in unconventional hydrocarbon source rocks: A small-angle neutron scattering (SANS) study on the Arthur Creek Formation, Georgina Basin, Australia

Small-angle neutron scattering (SANS) measurements were performed on 32 rock samples from the southern Georgina Basin, central Australia to assess nanopore anisotropy. Anisotropy can only be determined from oriented core material, hence the samples were cut perpendicular to bedding in cores selected from three wells that intersect the base of the hydrocarbon-bearing, organic-rich middle Cambrian Arthur Creek Formation; the latter is the source rock for both unconventional and conventional plays in the basin. The evolution of anisotropy of two-dimensional SANS intensity profiles with depth (for pore diameters ranging from 10 nm to 100 nm) was quantified and correlated with SANS intensity and total organic carbon (TOC) content. Our results confirm hydrocarbon generation at the base of the Arthur Creek Formation in the wells analysed. The nanopore anisotropy in the basal Arthur Creek Formation at the well locations CKAD0001 (oil generation window) and MacIntyre 1 (late oil generation window) varies roughly according to normal compaction. When the Arthur Creek Formation is in the gas window, as sampled at Baldwin 1, there is a strong (negative) correlation between the average vertical-to-horizontal pore shape anisotropy and SANS intensity. The results indicate that unconventional gas production from organic-rich regions of overmature shale may be adversely affected by abnormal pore compaction.

Preliminary Investigation of the Effects of Thermal Maturity on Redox-Sensitive Trace Metal Concentration in the Bakken Source Rock, North Dakota, USA.

Samples were taken at different levels of thermal maturity in the unconventional Bakken source rock. Programmed pyrolysis derived Tmax, solid bitumen reflectance, liptinite group maceral UV fluorescence, and nuclear magnetic resonance spectroscopy as different thermal maturity indicators were utilized in order to compare redox-sensitive trace metal (TM) concentration to maturity variations and disclose any probable relationship. Comparing redox-sensitive TMs with total organic carbon revealed the presence of anoxic/euxinic conditions in the depositional environment of the Bakken Shale. Although some of the TMs (V and Mo) exhibit slightly positive correlations with some of the thermal maturity indices used in this study, the correlations between other redox-sensitive TMs with maturity were neutral. Collectively, this study demonstrates that thermal maturity may have an impact on some redox-sensitive TMs such as Mo and V concentrations in marine sediments. Additional samples spanning higher maturities will need to be included because there is a possibility that an increase in thermal maturity may lead to the release and liberation of some redox-sensitive TMs from the organic matter (OM) directly. Remineralization and decomposition of OM with thermal maturity advance could release sulfur as a source of thermogenic H2S, which could accelerate pore water/rock interaction and authigenic Fe-sulfides. This could enhance the capability of uptaking of most of the redox-sensitive TMs and increase their concentration in pore water.

Geomechanical Characterization of Unconventional Source Rocks Using Rebound-Hardness Test and Mineral Mapping

Summary Rock strength is seldom considered important by the hydrocarbon industry to help monitor the drilling progress, evaluate wellbore stability, guide well completions, or predict the success of hydraulic fracturing in unconventional reservoirs. With respect to hydraulic fracturing, rock-elastic moduli are routinely used to evaluate stress anisotropy. However, rock strength may also be a crucial parameter to evaluate when designing hydraulic-fracturing strategies to stimulate production from the rock volume. However, because of the density of horizontal laminae comprising the rock structure within a vertical whole core, the true geomechanical anisotropy for both properties is difficult to measure from extracted core plugs. Often, core-plug drilling and extraction techniques do not produce intact core plugs to measure these parameters consistently because of the laminated rock fabric. The integrity of the rock makes it is difficult to interpret both elastic moduli and rock-strength measurements using the recovered plugs extracted from horizontal, vertical, and diagonal azimuths. To address that challenge, a new, nondestructive method is demonstrated in which rebound-hardness measurements taken across a specifically gridded, slabbed rock surface can provide an estimate of the rock strength. The collected rebound-hardness numbers (RHNs) are converted into unconfined-compressive strengths (UCSs) using an empirical algorithm. The empirical algorithm was developed using UCSs measured from core plugs correlated to RHNs measured from the face of those same core plugs. The derived UCSs are then used to represent the source rock's mechanical characteristics, which can be presented as a contour map across the surface. These results have been correlated to the mineralogy of the rock surface, quantified, and mapped using micro-X-ray-fluorescence (µ-XRF) elemental maps. Differences in UCS can then be correlated to the changing mineral content of the rock surface. This nondestructive estimation of rock strength was conducted to address the challenge of relating core-scale measurements to reservoir-scaled analysis to improve hydraulic-fracturing designs in unconventional source rocks.

From marine bands to hybrid flows: Sedimentology of a Mississippian black shale

AbstractOrganic‐rich mudstones have long been of interest as conventional and unconventional source rocks and are an important organic carbon sink. Yet the processes that deposited organic‐rich muds in epicontinental seaways are poorly understood, partly because few modern analogues exist. This study investigates the processes that transported and deposited sediment and organic matter through part of the Bowland Shale Formation, from the Mississippian Rheic–Tethys seaway. Field to micron‐scale sedimentological analysis reveals a heterogeneous succession of carbonate‐rich, siliceous, and siliciclastic, argillaceous muds. Deposition of these facies at basinal and slope locations was moderated by progradation of the nearby Pendle delta system, fourth‐order eustatic sea‐level fluctuation and localized block and basin tectonism. Marine transgressions deposited bioclastic ‘marine band’ (hemi)pelagic packages. These include abundant euhaline macrofaunal tests, and phosphatic concretions of organic matter and radiolarian tests interpreted as faecal pellets sourced from a productive water column. Lens‐rich (lenticular) mudstones, hybrid, debrite and turbidite beds successively overlie marine band packages and suggest reducing basin accommodation promoted sediment deposition via laminar and hybrid flows sourced from the basin margins. Mud lenses in lenticular mudstones lack organic linings and bioclasts and are equant in early‐cemented lenses and in plan‐view, and are largest and most abundant in mudstones overlying marine band packages. Thus, lenses likely represent partially consolidated mud clasts that were scoured and transported in bedload from the shelf or proximal slope, as a ‘shelf to basin’ conveyor, during periods of reduced basin accommodation. Candidate in situ microbial mats in strongly lenticular mudstones, and as rip‐up fragments in the down‐dip hybrid beds, suggest that these were potentially key biostabilizers of mud. Deltaic mud export was fast, despite the intrabasinal complexity, likely an order of magnitude higher than similar successions deposited in North America. Epicontinental basins remotely linked to delta systems were therefore capable of rapidly accumulating both sediment and organic matter.

Hydrous heating experiments at 130 °C yield insights into the occurrence of hydrogen sulfide and light alkanes in natural gas reservoirs

Improved understanding of the origin of produced volatiles from conventional reservoirs and unconventional source rocks is critical for petroleum exploration and production. A series of hydrous heating experiments using two immature Type II siliciclastic source rocks, Pennsylvanian Turner Mine shale (TMS) and Devonian New Albany Shale (NAS), at 130 °C over one to two years were conducted to assess gas generation at low temperature. Elemental sulfur (ES) was added to the NAS samples to evaluate the role of sulfur on thermochemical sulfate reduction (TSR). The produced volatile composition was investigated in situ using Raman spectroscopy at the end of the heating experiments. Results show that the two source rocks yield different types and concentrations of volatiles. Only CH4 and CO2 were detected following hydrous heating of the TMS source rock in contrast to CH4, C2H6, C3H8, and CO2 which were observed in experiments using NAS. Variations in the produced volatiles are likely the result of compositional differences within the respective source rock organic matter. Experiments involving ES show strong H2S signals that are likely due to the formation of H2S from the reaction of ES with water at 130 °C. H2S signals correlate with a greater relative concentration of CH4 and CO2 compared to experiments where ES was not added, on a time-normalized basis. The correlation between the presence of H2S and an increase in CH4 and CO2 concentration could indicate the occurrence of TSR. Here we propose that H2S in siliciclastic shale can be generated in the presence of ES at low temperatures via both disproportionation of ES into H2S and SO42−, and TSR. Our findings from this study provide experimental evidence that may aid efforts to interpret the origin of H2S in low-temperature sedimentary basins.

Electrical properties of unconventional source rocks from Micro-CT using numerical mixing law

Accurate rock characterization is critical in using resistivity and dielectric methods for source rocks. However, conventional mixing theories cannot address scenarios where the high volume inclusion exists for rocks with anisotropic electrical parameters. In this paper, an electromagnetic numerical technique using finite difference method was developed to investigate the electrical and anisotropic properties of source rocks based on 3D rock Micro-CT images. Numerical experiments were applied to study the effects of pyrites and fluids on the effective resistivity and electronic anisotropy in source rocks. It was found that less than 1% pyrite or brine significantly changed the electric property and enhanced their anisotropy.

Comparison of enigmatic diamonds from the Tolbachik arc volcano (Kamchatka) and Tibetan ophiolites: Assessing the role of contamination by synthetic materials

The enigmatic appearance of cuboctahedral diamonds in ophiolitic and arc volcanic rocks with morphology and infrared characteristics similar to synthetic diamonds that were grown from metal solvent requires a critical reappraisal. We have studied 15 diamond crystals and fragments from Tolbachik volcano lava flows, using Fourier transform infrared spectrometry (FTIR), transmission electron microscopy (TEM), synchrotron X-ray fluorescence (SRXRF) and laser ablation inductively coupled plasma mass-spectrometry (LA-ICP-MS). FTIR spectra of Tolbachik diamonds correspond to typical type Ib patterns of synthetic diamonds. In TEM films prepared using focused ion beam technique, we find Mn-Ni and Mn-Si inclusions in Tolbachik diamonds. SRXRF spectra indicate the presence of Fe-Ni and Fe-Ni-Mn inclusions with Cr, Ti, Cu, and Zn impurities. LA-ICP-MS data show variable but significantly elevated concentrations of Mn, Fe, Ni, and Cu reaching up to 70 ppm. These transition metal concentration levels are comparable with those determined by LA-ICP-MS for similar diamonds from Tibetan ophiolites. Mn-Ni (+Fe) solvent was widely used to produce industrial synthetic diamonds in the former USSR and Russia with very similar proportions of these metals. Hence, it appears highly probable that the cuboctahedral diamonds recovered from Kamchatka arc volcanic rocks represent contamination and are likely derived from drilling tools or other hard instruments. Kinetic data on diamond dissolution in basaltic magma or in fluid phase demonstrate that diamond does not form under the pressures and temperature conditions prevalent within the magmatic system beneath the modern-day Klyuchevskoy group of arc volcanoes. We also considered reference data for inclusions in ophiolitic diamonds and compared them with the composition of solvent used in industrial diamond synthesis in China. The similar inclusion chemistry close to Ni70Mn25Co5 for ophiolitic and synthetic Chinese diamonds scrutinized here suggests that most diamonds recovered from Tibetan and other ophiolites are not natural but instead have a synthetic origin. In order to mitigate further dubious reports of diamonds from unconventional tectonic settings and source rocks, we propose a set of discrimination criteria to better distinguish natural cuboctahedral diamonds from those produced synthetically in industrial environments and found as contaminants in mantle- and crust-derived rocks.

Thermal modelling of gas generation and retention in the Jurassic organic-rich intervals in the Darquain field, Abadan Plain, SW Iran

The petroleum system with Jurassic source rocks is an important part of the hydrocarbons discovered in the Middle East. Limited studies have been done on the Jurassic intervals in the 26,500 km2 Abadan Plain in south-west Iran, mainly due to the deep burial and a limited number of wells that reach the basal Jurassic successions. The goal of this study was to evaluate the Jurassic organic-rich intervals and shale gas play in the Darquain field using organic geochemistry, organic petrography, biomarker analysis, and basin modelling methods. This study showed that organic-rich zones present in the Jurassic intervals of Darquain field could be sources of conventional and unconventional gas reserves. The organic matter content of samples from the organic-rich zones corresponds to medium-to-high-sulphur kerogen Type II-S marine origin. The biomarker characteristics of organic-rich zones indicate carbonate source rocks that contain marine organic matter. The biomarker results also suggest a marine environment with reducing conditions for the source rocks. The constructed thermal model for four pseudo-wells indicates that, in the kitchen area of the Jurassic gas reserve, methane has been generated in the Sargelu and Neyriz source rocks from Early Cretaceous to recent times and the transformation ratio of organic matter is more than 97%. These organic-rich zones with high initial total organic carbon (TOC) are in the gas maturity stage [1.5–2.2% vitrinite reflectance in oil (Ro)] and could be good unconventional gas reserves and gas source rocks. The model also indicates that there is a huge quantity of retained gas within the Jurassic organic-rich intervals.

Integrated ground-based hyperspectral imaging and geochemical study of the Eagle Ford Group in West Texas

This study used ground-based hyperspectral imaging to map an outcrop of the Eagle Ford Group in west Texas. The Eagle Ford Group consists of alternating layers of mudstone – wackestone, grainstone – packstone facies and volcanic ash deposits with high total organic content deposited during the Cenomanian – Turonian time period. It is one of the few unconventional source rock and reservoirs that have surface representations.Ground-based hyperspectral imaging scanned an outcrop and hand samples at close ranges with very fine spatial resolution (centimeter to sub-millimeter). Spectral absorption modeling of clay minerals and calcite with the modified Gaussian model (MGM) allowed quantification of variations of mineral abundances. Petrographic analysis confirmed mineral identifications and shed light on sedimentary textures, and major element geochemistry supported the mineral quantification. Mineral quantification resulted in mapping of mudstone – wackestone, grainstone – packstone facies and bentonites (volcanic ash beds). The lack of spatial associations between the grainstones and bentonites on the outcrop calls into question the hypothesis that the primary productivity is controlled by iron availability from volcanic ash beds. Enrichment of molybdenum (Mo) and uranium (U) indicated “unrestricted marine” paleo-hydrogeology and anoxic to euxinic paleo-redox bottom water conditions.Hyperspectral remote sensing data also helped in creating a virtual outcrop model with detailed mineralogical compositions, and provided reservoir analog to extract compositional and geo-mechanical characteristics and variations. The utilization of these new techniques in geo-statistical analysis provides a workflow for employing remote sensing in resource exploration and exploitation.

Technology Focus: Formation Evaluation (August 2017)

Technology Focus Not too long ago, horizontal drilling revolutionized the petroleum industry. Emerging logging-while-drilling and geosteering technologies helped bring about multilateral, maximum-contact, and smart-completion wells, allowing reservoirs to be developed and produced much more efficiently and economically. This increased recovery, thus boosting reserves. In the process, formation evaluation plays a critical role in determining whether a producer or an injector is successful. More recently, efficient mass horizontal drilling and optimized multistage massive fracturing have turned traditionally nonreservoir source rock into sweet spots of energy strategy on a global scale. Production from unconventional reservoirs in the last decade has dramatically changed the petroleum industry, and this movement continues to evolve. Developing unconventional resources demands unconventional thinking, mainly because of the many challenges involved in evaluating tight source rocks. The two fundamental petrophysical properties, pore structure and wettability, are completely different between conventional reservoirs and unconventional source rocks. What may be next on the horizon? It is estimated that methane hydrates contain much more gas than shale plays, and, understandably, many countries are keen to explore this vast potential. As per recent news releases, China Geological Survey geoscientists and China National Petroleum Corporation engineers may have made a great technology breakthrough by being able to test significant hydrate-gas production in the South China Sea. If this is sustainable, exploring hydrate gas may be the next game changer for the energy industry. Evaluating hydrate gas formations would not be easy, however, and producing them safely, economically, and in an environmentally friendly way would be very challenging. But, I have high hopes that future technologies will be able to resolve these challenges to produce hydrate gas conventionally so it can be used to improve living standards. Recommended additional reading at OnePetro: www.onepetro.org. SPE 182448 The Petrophysics Role of Low-Resistivity Pay Zone of Talang Akar Formation, South Sumatera Basin, Indonesia by Z. Holis, SKK Migas, et al. SPE 183883 Using Digital Rock Modeling To Estimate Permeability and Capillary Pressure From NMR and Geochemical Logs by Hao Zhang, Baker Hughes, et al. SPE 183800 An Innovative Approach for Integrated Characterization and Modeling of a Complex Carbonate Reservoir by F. Ben Amor, Schlumberger, et al.

An Integrated Approach for the Characterization of Shales and Other Unconventional Resource Materials

Production of oil and gas from unconventional source rocks (shales) has increased significantly in recent years, reflecting a shift in the focus of the oil and gas industry from conventional to unconventional oil/gas resources. An improved insight into the pore structure characteristics of these important porous materials will enable a better understanding and further optimization of the production behavior from such vast hydrocarbon resources. In particular, characterization of porosity and permeability of shales is the key to accurately estimating the initial oil and gas in place and fluid flow through these rocks. However, evaluating the pore structure of shales presents technical challenges due to the presence of a range of pores, from the nanometer to the micrometer size. Characterization of the entire range of pore sizes requires an all-inclusive study employing a variety of techniques. Such an integrated approach is followed in this work to understand the pore structure of Monterey shale samples as...