Unconventional Hydrocarbon Reservoirs Research Articles

Lateral heterogeneity of basin‐plain turbidites of the Cloridorme Formation, Quebec, Canada: Implications for horizontal well prediction

AbstractFacies models for basin‐plain turbidite systems often depict very simplistic event‐bed geometries that are tabular at the kilometre scale. However, recent studies have demonstrated more complex facies architectures, including rapid changes in event‐bed thickness and facies composition. This lateral event‐bed heterogeneity can have a significant impact on reservoir heterogeneity prediction in basin‐plain turbidite systems developed for hydrocarbon production, carbon sequestration or geothermal energy. Coastal outcrops on the Gaspé Peninsula in Quebec expose the Middle Ordovician Cloridorme Formation, a synorogenic ‘flysch’ turbidite system developed in the Taconic foreland basin. The formation is interpreted to occupy a basin‐floor position due to long‐distance (tens of kilometres) correlations of bedsets in the direction of palaeocurrent. This outcrop‐based study of the Cloridorme Formation utilises drone photogrammetry, centimetre‐scale graphic logs and handheld gamma ray scintillometry data to better understand the detailed turbidite and hybrid event‐bed architecture in a basin‐plain setting. While most beds in this outcrop study can be traced for 500 m or more in a downcurrent direction, these results indicate significant intra‐bed and inter‐bed lateral complexity, including changes in bed thickness, grain‐size distribution and mud content. The quantification of these lateral changes and comparison with other well‐constrained outcrop analogues refines the environment of the Cloridorme Formation and aids in the prediction of subsurface heterogeneity in conventional and unconventional hydrocarbon reservoir systems through reservoir model parameterisation, as well as the characterisation of lateral heterogeneity important for horizontal‐well geosteering and completion strategies.

Integrated multispectral remote sensing approach for high-resolution spectral characterization and automated mapping of carbonate lithofacies

Field-based high-resolution carbonate facies mapping is often challenging due to the limited accessible exposure, high-degree of heterogeneity, and lack of distinct natural characteristics between different lithofacies. To mitigate this issue, we proposed a novel approach by integrating multispectral remote sensing, advanced image processing techniques, and supervised classification to perform high-resolution carbonate lithofacies mapping and utilized the extensive Mesozoic carbonate in Saudi Arabia as an example. For this study, the Tuwaiq Mountain Formation (TMF) was selected not only because of its wide aerial distribution but also its importance as conventional and unconventional hydrocarbon reservoirs in the subsurface. Our proposed method was able to map and delineate different members (T1, T2, T3) and key lithofacies in the TMF. In addition, based on the spectral characteristics, the middle member of TMF (T2) can be further subdivided into two subunits (T2-a of higher reflectance & T2-b of lower reflectance). These findings are further corroborated by detailed microfacies analysis, which validates the presence of two sub-members of T2 (T2-a: Spiculitic foraminiferal wackestone and T2-b: Coralline floatstone facies). This resulted in a revised and accurate lithofacies map that made significant modifications over older maps. The overall accuracy of TMF lithofacies is 93.4 % with a kappa coefficient of 0.88. This study demonstrates that multispectral remote sensing approach are effective at distinguishing different carbonate units and providing high-resolution carbonate facies maps. The proposed approach should be applicable to other carbonate outcrops globally and could help in improving carbonate lithofacies mapping where the outcrops are not accessible.

Distribution patterns and controlling factors of beach bars in Qinghai Lake, NW China

The significance of beach-bar reservoirs, which are intricately linked to unconventional hydrocarbon reservoirs, has gained increased attention. This study elucidates the complex mechanisms governing the formation, spatial distribution, and morphological characteristics of beach bars in Qinghai Lake, NW China, highlighting the interplay of lake-level fluctuations, wind wave dynamics, sediment provenance, and terrain gradient. Our findings reveal that large-scale lake-level fluctuations primarily dictate the initial formation settings of beach bars, while small-scale fluctuations refine their internal stratification and sedimentary features. Wind wave dynamics play a critical role in defining suitable depth zones for beach bar development, influencing their morphology and resulting in distinct sedimentary characteristics across different lake zones. Furthermore, the study categorizes beach bars into three main systems based on sediment provenance—bedrock, alluvial fan (fan delta), and braided river systems—each exhibiting unique compositional and structural attributes. Terrain gradient around the lake significantly affects beach bar formation, with areas having a gradient less than 0.7° being particularly favorable. This research advances our understanding of lacustrine beach bar dynamics, offering insights into their potential as indicators of past environmental conditions and their implications for hydrocarbon exploration. The comprehensive analysis of controlling factors provides a foundation for predicting beach bar distribution and contributes to the broader field of sedimentary geology by integrating multi-disciplinary approaches to study lacustrine sedimentary processes.

Hydraulically Fractured Horizontal Wells: A Technology Poised To Deliver Another Energy-Related Breakthrough of Enormous Scale

_ The development of efficient technologies for drilling and hydraulically fracturing horizontal wells has enabled the US to more than double hydrocarbon production since 2005 (Fig. 1), thereby providing unprecedented levels of energy security for America. America’s doubling of hydrocarbon output has also held down the price of energy worldwide, and by doing so, accelerated global economic growth. And it has helped reduce the greenhouse gas (GHG) intensity of energy production by backing out “dirtier” forms of energy, such as coal. Energy security—economic growth—reduced GHGs vented to the atmosphere: That’s a winning combination. One that America and many other countries have benefitted from immensely. Given the enormous positive contributions, it is worth noting that 20 years ago, few if any in our industry foresaw the immense potential of this technology, seeing it as being only applicable for extracting gas from ultratight reservoirs like the Barnett Shale, if they were aware of the technology at all. This oversight caused many companies to wait too long before deciding to pursue unconventional reservoirs and caused several of the “shale gas” pioneers to be late in recognizing that hydraulically fractured horizontal wells (HFHWs) could also be successfully applied in liquid-rich plays such as the Eagle Ford and Permian Basin. These are plays that today deliver far more value than that derived from the gas-prone reservoirs that comprised the initial suite of targets. And while events have proven beyond a doubt that HFHWs are a powerful tool for economically extracting hydrocarbons from both gas-prone and liquids-rich unconventional reservoirs, it seems likely that many in our industry are overlooking a third significant application of this technology: The use of HFHWs to extract heat from the Earth’s crust that can be utilized to generate electricity. Old Story, New Horizon What makes this third application particularly compelling as an investment opportunity is that the primary physical challenge that needs to be overcome to achieve attractive rates of return is strikingly similar to that which the oil and gas industry had to surmount to make both gas and liquids-rich unconventional reservoirs economic. The key to success in all of these cases boils down to an ability to create via hydraulic stimulation a sufficiently large amount of conductive, connected, fracture surface area. With this, one can reliably expect per-well production rates to be economic given the extremely slow rate at which hydrocarbons—and heat—move through unconventional reservoirs and the hot, dry, basement rocks that contain the bulk of the world’s geothermal resources. That converting from vertical to horizontal well geometries was critical for unlocking the potential of unconventional hydrocarbon reservoirs is now obvious, with this switch having allowed petroleum engineers to increase per-well fracture surface areas by several orders of magnitude. This move increased per-well flow rates by similar amounts (i.e., from subeconomic flow rates from hydraulically fractured vertical wells (HFVWs) to flow rates of thousands of BOE/D from HFHWs.

EFFECTS OF POROSITY ON THE STRENGTH AND MECHANICAL BEHAVIOUR OF POROUS GEO-MATERIALS UNDER CYCLIC LOADING

Most rocks in nature are porous and usually saturated with different fluids such as water, oil, and gas. The conventional and unconventional hydrocarbon reservoirs are mainly associated with sedimentary formations. The main rocks of these reservoirs are sandstone (porous rock), limestone and oil shale (tight rock), which are associated with varying porosity. Hence, porosity serves as a fundamental parameter for most reservoir rocks. In this research, the effect of porosity on the mechanical behaviour of geo-materials and its fatigue behaviour was investigated. For this purpose, a total of five geo-material sample groups with varying porosities were prepared and designated, i.e. groups A, B, C, D, and E. Group A exhibited the highest porosity 20-21.5%, while group E had the lowest porosity 2-3%, respectively. The conventional quasi-static strength tests and cycle loading tests with constant frequency and amplitude were performed on the samples and different results were obtained. The samples belonging to group E, with the lowest porosity (2-3%), exhibited the highest mechanical strength, elastic modulus and fracture toughness values and the lowest Poisson's ratio compared to those of higher porosity samples. During the cyclic loading period, the fatigue stress-life graph of the E group has the lowest slope compared to the other groups. It means that the slope of the graph increases as the porosity increases in all groups. Therefore, the E group has the lowest porosity and the longest fatigue life time, i.e. porosity and fatigue resistance have an inverse correlation.

Concise extraction and characterization of the pore-throat network in unconventional hydrocarbon reservoirs: A new perspective

In this study, a new image-based method for the extraction and characterization of pore-throat network for unconventional hydrocarbon storage and exploitation is proposed. “Pore-throat solidity”, which is analogous to particle solidity, and a new method for automatic identification of pores and throats in tight sandstone oil reservoirs are introduced. Additionally, the “pore-throat combination” and “pure pore” are defined and distinguished by drawing the cumulative probability curve of the pore-throat solidity and by selecting an appropriate cutoff point. When the discrete grid set is recognized as a pore-throat combination, Legendre ellipse fitting and minimum Feret diameter are used. When the pore and throat grid sets are identified as pure pores, the pore diameter can be directly calculated. Using the new method, the analytical results for the physical parameters and pore radius agree well with most prior studies. The results comparing the maximum ball and the new model could also prove the accuracy of the latter's in micro and nano scales. The new model provides a more practical theoretical basis and a new calculation method for the rapid and accurate evaluation of the complex processes of oil migration.

Silicified unicellular green microalga as a significant oil source in the Late Paleozoic alkaline lake-playa deposit, Junggar Basin, NW China

Siliceous mudstones and chert-shale couplets are primary source rocks for many large paleo-oil reservoirs over the world. It is well established that photosynthetic organisms can be exceptionally well preserved in silica precipitates, but the fate of the trapped organic matter (OM) during burial remains poorly studied. Here, dense unicellular microbial fossils have been recently discovered in the cherts of the Late Paleozoic alkaline saline lake deposit in NW Junggar Basin, NW China. We use petrographic observations and organic geochemical analysis to study the origin of unicellular microbes and how silicified organic matter generate and expel hydrocarbons. A 300-m-long oil shale core shows overall low levels of porosity, permeability and total organic carbon contents (generally <0.5 wt%), but very high extracts (on average 0.26 wt%), suggesting that the rich extracts were mostly indigenous and the original organic matter had a high hydrocarbon conversion. Analysis of biomarkers and silicified fossils both suggest that the bio-precursor for the organic matter is a special green alga. Reconstruction of silica diagenesis of cherts indicates that both the trapped lipids and hydrocarbons in silicified microbial cells and extracellular polymeric substances had been effectively expelled out during the transformations of Opal-A to microcrystalline quartz and during OM thermal maturation. Exceptional OM preservation and effective oil expelling ways render siliceous source rocks as excellent unconventional hydrocarbon reservoirs.

Characterising the economic Proterozoic Glyde Package of the greater McArthur Basin, northern Australia

The greater McArthur Basin is an informal term for a Palaeo-to-Mesoproterozoic sedimentary system that consists of terranes from the McArthur Basin, Birrindudu Basin, and the Tomkinson Province. These spatially distant basins are interpreted to connect in the subsurface based on geophysical, lithological, and geochronological evidence. The coeval sedimentary units of the greater McArthur Basin were subdivided into non-genetic depositional ‘packages’ bookended by regional unconformities. In ascending order, these packages are the: Redbank, Goyder, Glyde, Favenc, and Wilton Packages. The ca. 1660–1610 Ma Glyde Package is the focus of this study and includes the economically important Barney Creek Formation, found in the McArthur Basin sensu stricto. The Barney Creek Formation hosts the world-class, sediment-hosted, Zn-Pb-Ag McArthur River deposit. Importantly, it is also a key petroleum source rock and unconventional hydrocarbon reservoir, containing Australia’s geologically oldest oil and gas discoveries and forming a part of the McArthur Petroleum Supersystem. Consequently, identifying chronostratigraphically similar units elsewhere in the greater McArthur Basin is important for explorers in finding analogous economic resources.In situ Rb–Sr geochronological results of the Barney Creek Formation shales sourced from borehole LV09001 yielded ages of 1634 ± 59 Ma and 1635 ± 67 Ma. Shale samples from Fraynes Formation in borehole Manbulloo S1 were dated at 1630 ± 57 Ma and 1636 ± 42 Ma using the same approach. These ages are in good agreement with U–Pb ages of tuffaceous layers from the same units, suggesting that they represent their early burial histories and not secondary, post-depositional events. These results indicate that the Fraynes Formation and the Barney Creek Formation are direct chronostratigraphic equivalents, with ages within analytical error of each other.In addition to the geochronological similarities, the δ13Ccarb,87Sr/86Sr, and δ88/86Sr isotopic constraints from both units also display parallel geochemical fingerprints up-section. These include a positive δ13Ccarb excursion of ∼2.0 ‰, a trend towards more crustal-dominated 87Sr/86Sr ratios, and a negative δ88/86Sr excursion of ∼-0.25 ‰. These findings further support the application of isotopic chemostratigraphy as a powerful tool to correlate distal carbonaceous rocks in the basin system. Importantly, these geochemical fingerprints also show that the McArthur Group and the Limbunya Group experienced similar changes in palaeoenvironments during the evolution of the basin system. However, trace element data collated in this study indicates that they may have recorded different, heterogeneous palaeoredox histories. Geochemical models based on redox-sensitive trace elements V and Mo suggest that the Fraynes Formation sustained a much more euxinic water column as opposed to the Barney Creek Formation. These differences may have implications for the accumulation and preservation of base metals and hydrocarbons within the sediment.

Origins of pressure dependent permeability in unconventional hydrocarbon reservoirs

Unconventional hydrocarbon assets represent a rapidly expanding proportion of North American oil and gas production. Similar to the incipient phase of conventional oil production at the turn of the twentieth century, there are ample opportunities to improve production efficiency. In this work we demonstrate that pressure dependent permeability degradation exhibited by unconventional reservoir materials is due to the mechanical response of a few commonly encountered microstructural constituents. In particular, the mechanical response of unconventional reservoir materials may be conceptualized as the superposed deformation of matrix (or ~ cylindrical/spherical), and compliant (or slit) pores. The former are representative of pores in a granular medium or a cemented sandstone, while the latter represent pores in an aligned clay compact or a microcrack. As a result of this simplicity, we demonstrate that permeability degradation is accounted for through a weighted superposition of conventional permeability models for these pore architectures. This approach permits us to conclude that the most severe pressure dependence is due to imperceptible bedding parallel delamination cracks in the oil bearing argillaceous (clay-rich) mudstones. Finally, we demonstrate that these delaminations tend to populate layers that are enriched with organic carbon. These findings are a basis for improving recovery factors through the development of new completion techniques to exploit, then mitigate pressure dependent permeability in practice.

Introduction to special section: Understanding and modeling the architecture of conventional and unconventional hydrocarbon reservoirs

Introduction to special section: Understanding and modeling the architecture of conventional and unconventional hydrocarbon reservoirs

Uniformity and volume-representativity of consecutive submillimetre wafers of shale for SANS and USANS investigations

(Ultra) Small Angle Neutron Scattering (SANS/USANS) is a non-destructive technique suitable for characterization of porous structures from nano- to micro-pore size (1 nm to 20 μm), which has been widely used to characterize accessible and inaccessible porosity in tight unconventional hydrocarbon reservoirs (e.g., shales). In this study, SANS and USANS are used to examine the degree of nano- to micropore uniformity of the rock body on sub-millimetre to centimetre scale. This study presents a test of the hypothesis of volume representativity of pore structure information measured by SANS and USANS for shale wafers (0.22–1 mm) cut from six North American unconventional shale cores of different maturities (New Albany Shale and Marcellus Shale). Experimental reproducibility of USANS is further investigated for two wafers measured using various acquisition times. All samples show that fluctuations of the relative intensity generally decrease from the USANS Q-range (pore size from around 200 nm to 20 μm) to most of the SANS Q-range (pore size from around 5 nm to 700 nm), and peaks in the SANS large-Q region (for pores smaller than about 5 nm). There is a positive correlation between the spatial fluctuation of the relative SANS intensity and the scattering power of shales. In addition, the scattering intensity and its fluctuations is larger for the less mature shale cores. Shale is known to be highly heterogenous and the hypothesis of uniformity does not apply at sub-millimetre scale even for samples that appear homogeneous at visual inspection. This study presents an approach to minimise the variation through sample selection, data interpretation methodology and instrumental reproducibility tests. The best values of the microstructural spatial uniformity for the apparently homogeneous sections of a core (i.e., the SANS and USANS intensity variation) is less than ±10%.

Pore morphology effect on elastic and fluid flow properties in Bakken formation using rock physics modeling

Unconventional geo-resources are critical due to their important contributions to energy production. In this energy transition and sustainability era, there is an increased focus on CO2-enhanced oil recovery (CO2-EOR) and geological CO2 storage (GCS) in unconventional hydrocarbon reservoirs, and the extraction of hot fluid for energy through enhanced geothermal systems. However, these energy solutions can only be achieved through efficient stimulation to develop a complex fracture network and pore structure in the host rocks to extract heat and hydrocarbon, or for CO2 storage. Using Bakken formation well data and rock physics models, this study aimed to identify the post-depositional effect of pore structure on seismic velocity, elastic moduli, and formation fluid; and further predict the best lithofacies interval for well landing, and the implications for fluid (gas, oil, and water) recovery in naturally- and often systematically-fractured geosystems. The KT and DEM models' predictions show distinct formation intervals exhibiting needle-like pores and having higher seismic velocities (Vp and Vs) and elastic moduli (K and µ), relative to other formation intervals that exhibit moldic pores. At the same fluid concentration, the needle-like pores (small aspect ratios) have a higher impact on elastic moduli, Vp, and Vs than on the moldic spherical pores with all other parameters held constant. Vp is affected more than Vs by the properties of the saturating fluid (gas, oil, or water) with Vp being greater in Bakken formation when it is water-saturated than when it is gas-saturated. Vs exhibit the reverse behavior, with Vs greater in the gas-saturated case than in the water-saturated case. Further, analyses suggest that the middle Bakken formation will have a higher susceptibility to fracturing and faulting, and hence will achieve greater fluid (oil and water) recovery. Our findings in this study provide insights that are relevant for fluid production and geo-storage in unconventional reservoirs.Article highlightsIntegrated well log data and rock physics models.Investigated the effect of changes in pore structure on elastic properties and fluid flow in shale.Increase in porosity causes a reduction in elastic moduli and seismic velocities.Vp is more affected by pore geometry than Vs depending on density and properties of saturating fluid.Lithofacies with needle−like pores are more susceptible to fracturing than lithofacies with intragranular pores.

Ionic liquids as clay stabilizer additive in fracturing fluid

Swelling clays in hydrocarbon-bearing rocks' mineralogy pose several challenges in developing unconventional hydrocarbon reservoirs, including permeability impairment and fracture network retardation. Different clay stabilizers are incorporated in fracturing fluids to help solve this challenge. The effect of clay swelling on the compressive strength of rock was studied using unconfined compression and scratch tests. Also, the tensile strength of rocks exposed to different clay stabilizers was tested using a Brazilian disc test and a breakdown pressure experiment. A medical CT scan of the tested samples was thoroughly studied to inspect the propagation and distribution of the fractures during breakdown pressure experiments. The results revealed that, in comparison to the base scenario, where water was utilized as the fracturing fluid, the clay stabilizers reduced clay swelling and decreased compressive strength. A higher reduction in breakdown pressure and tensile strength was noticed in ionic liquid-based fracturing fluid compared to those treated with tested organic salt. Moreover, the presence and growth of a fracture network were confirmed by medical CT images.

Spatial distribution of micro- and nanoporosity in Oligocene Menilite and Cretaceous Lgota mudstones (Outer Carpathians): Organic porosity development as a key to understanding unconventional hydrocarbon reservoirs?

The Oligocene Menilite Beds are considered the most important source rock for hydrocarbon accumulation in the Polish Carpathian region, whereas the Cretaceous Lgota Beds have been regarded as an additional potential source rock. Understanding their petrophysical and geochemical properties is essential for evaluating the hydrocarbon potential of these beds.This paper presents mineral and organic porosity characterization and focuses on factors responsible for the development of organic pores as a reflection of the depositional and diagenetic processes. Mudstones were evaluated as potential source and reservoir rocks, describing their diagenetic and thermal history and examining their effective porosity and permeability. The results show that the Lgota Beds mudstone in the Huczwice quarry is thermally mature (late oil/early gas window, Tmax 460–470 °C), containing type III kerogen and TOC between 0.68 wt% and 4.2 wt%, in contrast to the Menilite Beds mudstone (Monasterzec outcrop), which is thermally immature (Tmax<426 °C), containing type II kerogen and TOC content from 1.24 wt% to 8.7 wt%. The geochemical properties show that the Lgota mudstone is currently an ineffective source rock, whereas the Menilite mudstone can be a potential source rock. SEM-identified pores include mineral pores, organic pores and microfractures. Organic porosity is observable both in immature oil-prone type II kerogen and highly mature gas-prone type III kerogen. The amount of pores in organic matter increases with maturity, and no relation between TOC and organic porosity development has been observed. Palynofacies analysis showed that the Menilite and Lgota mudstones are dominated by amorphous organic matter, and that the Lgota mudstone also contains opaque woody material. MICP measurements indicate high (up to 15%) effective porosity values for the Menilite Beds and up to 8% for the Lgota Beds, with very low permeability values (<0.1 mD) in both cases. Isotherms obtained from nitrogen adsorption are type IV for the Lgota Beds and type II for the Menilite Beds, while the BET surface areas are around 13 m2/g and 3 m2/g, respectively. The Lgota Beds demonstrate advanced diagenetic processes such as compaction, cementation, dissolution, replacement, and transformation, which contributed to the significant reduction in porosity, while the Menilite Beds represent an early stage of burial with the prevailing impact of compaction and thus less destruction of original pores. Finally, the Menilite Beds from the Monasterzec outcrop do not demonstrate sufficient conditions for shale-oil/-gas source rock due to the lack of proper thermal maturity. Such criterion is fulfilled by the Lgota Beds in the Huczwice quarry, but due to very low hydrocarbon potential, the Lgota mudstone is an ineffective source rock. However, given the other petrophysical and geochemical properties, the analysed formations may constitute a basis for further research on the occurrence of unconventional reservoirs in the entire Carpathian region.

Occurrence and preservation of primary organic matter in a hybrid unconventional reservoir: Montney Formation, Western Canada Sedimentary Basin

The Lower Triassic Montney Formation of the Western Canada Sedimentary Basin (WCSB) is a world-class unconventional hydrocarbon resource in North America. It was deposited on the northwestern margin of Pangaea at mid-latitudes in an arid climate and after major mass extinction at the Late Permian-Triassic boundary. Despite decades of exploration and economic importance, the origin of organic matter and source of accumulated hydrocarbons is not well understood. The Montney Formation is primarily composed of dolomitic siltstone with a mean total organic carbon (TOC) content of ≤1 wt%. In this study, we re-examined samples from an Alberta Geological Survey (AGS) data release in 2010 on Montney Formation organic petrography and expand the sampling and analysis to further investigate organic matter type, thermal maturity, and possible internal hydrocarbon source intervals within the Montney Formation as well as organic matter preservation and depositional environment by integrating programmed pyrolysis, organic petrography, and molecular geochemistry.Organic petrography and molecular geochemistry show that millimeter to centimeter thick mudstone intervals with TOC ≤ 1 wt%, are dominantly comprised of Type II marine kerogen (Prasinophyte and Tasmanites) with minimal terrigenous organic matter. The presence of these organic-rich mudstone beds in central and western Alberta reveals intra-formational sources of hydrocarbons within the Montney Formation, in addition to hydrocarbons sourced from overlying organic-rich source rocks (i.e., Triassic Doig and Jurassic Gordondale). These results confirm that the Montney Formation can be considered as a hybrid unconventional hydrocarbon reservoir with an interbedded source and reservoir.Molecular geochemistry data suggest that photic zone euxinia (PZE) was favorable for the preservation of organic matter during deposition of the Montney Formation. However, in many instances, this only happened during very short periods similar to depositional conditions on the offshore present day Namibian shelf. Traces of terrigenous organic matter were able to reach the basin, likely in the form of inertinite and combustion-derived polycyclic aromatic hydrocarbons (PAHs). Although the results of this study show there are source rock intervals within the Montney Formation, a comprehensive organic petrography and geochemistry study on a series of full-length Montney cores throughout the basin will help to ascertain the major paleo depositional variation and their effect on organic matter preservation as well as hydrocarbon source intervals and their contribution to WCSB petroleum systems.

Quantitative characterization of unconventional (tight) hydrocarbon reservoir by integrating rock physics analysis and seismic inversion: a case study from the Lower Indus Basin of Pakistan

Quantitative characterization of unconventional (tight) hydrocarbon reservoir by integrating rock physics analysis and seismic inversion: a case study from the Lower Indus Basin of Pakistan

Pore characterization of unconventional reservoirs

This study proposes an image-based idea for analyzing the complex geometric characteristics of reservoir spaces using various change curves of the pore geometric attributes to subdivide and evaluate tight reservoir rocks from micron to centimeter thicknesses. Using advanced imaging and image-processing technologies, in this study, we transform information from reservoir images into a vertical stratigraphy via an imaging-based method. The new parameter system incorporates three categories of parameters, size (S), morphology (M), and direction (D), to quantitatively and comprehensively characterize the pores of unconventional reservoir rocks. Given these three categories of the parameters, the curve at a certain depth value can be used to clearly identify obvious interfaces, which constitute high tip values. These interfaces may indicate that the hydrodynamic conditions, stress conditions of the reservoir, temperature and pressure, or other physical or chemical conditions changed significantly at these points, allowing the sedimentary compaction process to be well documented at the microscale level. This indicates that, from a micro-level perspective, we can find micro-evidence of the hydrodynamic conditions at the time of formation. Such information can help strengthen our understanding of the geological formation processes of unconventional hydrocarbon reservoirs.

Evidence of Hydrocarbon Generation and Overpressure Development in an Unconventional Reservoir Using Fluid Inclusion and Stable Isotope Analysis From the Early Triassic, Western Canadian Sedimentary Basin

Deep burial of sedimentary basins results in the development of complex diagenetic environments influenced by pressure, temperature, and metasomatic chemical processes. Fracture systems resulting from deep tectonic-related burial can provide archives of physio-chemical characteristics during burial helping unravel diagenetic events such as hydrocarbon migration and paleobarometry. The Early Triassic Montney Formation in the Western Canadian Sedimentary Basin is a highly productive unconventional hydrocarbon reservoir that has undergone multiple phases of tectonic-related burial and uplift resulting in the formation of a series of calcite-filled fracture systems. These fracture systems occur as vertical to sub-vertical fractures, brecciated zones, and horizontal bedding-plane parallel fractures that are rich in co-occurring, but not co-genetic aqueous and petroleum fluid inclusion assemblages. Fluid inclusion microthermometry, Raman spectroscopy, and stable isotope analysis of these fracture systems and host rock reveals paleobarometric and temperature conditions during fracture formation. Vertical fractures formed at temperatures exceeding 142°C during peak burial associated with the Laramide orogeny ∼50 Ma. Similarities in modeled oxygen isotope values of calcite parent fluids and pore water implicate locally sourced carbonate in fracture calcite. Therefore, low permeability and closed system-like conditions were prevalent throughout initial fracture formation and cementation. Petrographic analysis of brecciated and horizontal fractures show evidence of hydrocarbon generation and migration into fracture-filling calcite. Modeling of petroleum inclusion paleobarometry indicates entrapment pressures approaching or even exceeding lithostatic pressure consistent with the development of overpressure associated with the thermal maturation of organic matter following peak burial. Combined use of aqueous and petroleum fluid inclusions in this deeply buried sedimentary system offers a powerful tool for better understanding diagenetic fluid flow, the timing of hydrocarbon migration/maturation, and helps constrain the pressure-temperature history important for characterizing economically important geologic formations.

Approximation of P-, S1-, and S2-wave reflection coefficients for orthorhombic media

Orthorhombic (ORT) media are commonly used in the descriptions of subsurface strata during the exploration and exploitation of unconventional hydrocarbon reservoirs. In anisotropic media, seismic waves propagating in ORT media usually occur as quasi-P, quasi-S1, and quasi-S2 waves. Approximating the phase velocities and reflection coefficients of these waves is of great significance for predicting the properties of unconventional reservoirs, such as their elastic parameters, fracture azimuths, and fracture densities. At the incidence angles of P waves, we have developed formulas to approximate the reflection coefficients of quasi-P, quasi-S1, and quasi-S2 waves based on their first-order phase velocities and polarization vectors. Under weak anisotropy and weak impedance contrast assumptions, in the [ X, Z] and [ Y, Z] symmetry planes, our approximations basically match Rüger’s approximations at small-to-moderate incidence angles. Numerical analyses verify that our approximations are accurate at all azimuth angles under high impedance contrast and strong anisotropy. Two important innovations are provided in our manuscript. First, the errors in the proposed reflection coefficients only lie in the first-order phase velocities and polarization vectors. Second, we use lower-upper factorization to decompose matrix-dependent reflection coefficients into multiple simple nested formulas, which can be used to calculate the reflection coefficients without matrix operations.

A review of methods, applications and limitations for incorporating fluid flow in the discrete element method

The past decade has witnessed the substantial growth in research interests and progress on the subject of coupled hydro-mechanical processes in rocks and soils, driven mainly by the surge of research in unconventional hydrocarbon reservoirs and associated hazards. Many coupling techniques have been developed to include the effects of fluid flow in the discrete element method (DEM), and the techniques have been applied to a variety of geomechanical problems. Although these coupling methods have been successfully applied in various engineering fields, no single fluid/DEM coupling method is universal due to the complexity of engineering problems and the limitations of the numerical methods. For researchers and engineers, the key to solve a specific problem is to select the most appropriate fluid/DEM coupling method among these modeling technologies. The purpose of this paper is to give a comprehensive review of fluid flow/DEM coupling methods and relevant research. Given their importance, the availability or unavailability of best practice guidelines is outlined. The theoretical background and current status of DEM are introduced first, and the principles, applications, and advantages and disadvantages of different fluid flow/DEM coupling methods are discussed. Finally, a summary with speculation on future development trends is given.