Oil production from shale and tight formations will increase to more than 6 million barrels per day (b/d) in the coming decade, making up most of total U.S. oil production (> 50%). However, achieving an accurate formation evaluation of shale faces many complex challenges. One of the complexities is the accurate estimation of shale properties from well logs, which is initially designed for conventional reservoirs. When we use the well logs to obtain shale properties, they often cause some deviations. Therefore, in this work, we combine cores and well logs together to provide a more accurate guideline for estimation of total organic carbon, which is primarily of interest to petroleum geochemists and geologists.
Our work is based on Archie's equation. Resistivity log will lead to some incorrect results, such as total resistivity, when we follow the conventional interpretation procedure in well logs. Porosity is another complex parameter, which cannot be determined only by well log, i.e. density, NMR, and Neutron log. Therefore, the flowchart of TOC calculation includes five main parts: (I) the shale content calculation using Gamma log; (II) the determination of shale distributions using Density and Neutron logs and cross-plot; (III) the calculation of total resistivity at different distribution types; (IV) obtaining porosity using core analysis, NMR and density logs; and (V) the calculation of TOC from modified Archie's equation.
The results indicate that the shale content has a strong effect on estimation of water saturation and hydrocarbon saturation. Especially, the effect of shale content is exacerbated at a low water saturation. A more accurate flowchart for TOC calculation is established. Based on Archie's equation, we modify total resistivity and porosity by combining Gamma Log, Density Log, Neutron Log, NMR Log, and Cross-plot. An easier way to estimate porosity is provided. We combine the matrix density and kerogen density together and obtain them from core analysis. Poupon's et al. (1954) laminar model has some limitations when applying in shale reservoirs, especially at a low porosity.
Literature surveys show few studies on the flowchart of TOC calculation in shale reservoirs. This paper provides some insights into challenges of well logs, core analysis in shale reservoirs and a more accurate guideline of TOC calculation in shale reservoirs.
Determination of ideal horizontal targets for unconventional reservoirs often necessitates an understanding of the reservoir from the global tectonic to the sub-microscopic scale. When selecting a target zone, it is necessary to consider the abundance, composition, and delivery of sediment to basins; the production, preservation, and alteration of organic matter; and the diagenetic and structural modification of the stratigraphic section. Here, we focus on two sedimentologic phenomena common to the Marcellus Shale of the Appalachian Basin of southwestern Pennsylvania. Namely, we explore the strategy of targeting high organic carbon/biogenic silica facies and the challenges posed by encountering carbonate concretion horizons.
Geochemical observations including Si/Al and Si/Zr, and thin section and scanning electron microscopy indicate abundant recrystallized biogenic quartz cement in the Marcellus Shale. Burial models suggest that prior to the end of mechanical compaction; the Marcellus entered the oil window, and presumably began generating organic matter-hosted porosity at a depth of ~1200m. Notably, at similar organic carbon content, samples with elevated biogenic silica yield higher porosity and permeability. These observations suggest that biogenic quartz may play a role in the deliverability of hydrocarbons by providing a compaction resistant framework conducive to the preservation of organic matter-hosted pores and pore throats. Further, biogenic quartz-rich facies demonstrate increased rates of penetration allowing for more efficient drilling of laterals.
However, carbonate concretions encountered while drilling horizontal Marcellus Shale wells negatively affect drilling operations by reducing drilling rates, damaging bits, and requiring excessive steering corrections to penetrate or extricate the bit from the horizon. Carbonate concretions form by the anaerobic oxidation of methane in a narrow zone perhaps just a few meters below the seafloor. Crucial to this mechanism is a slowing or pause in sedimentation rate that would have held the zone of carbonate precipitation at a fixed depth long enough for concretions to grow. Using this model, we attempt to predict the size and location of concretions to avoid encountering them while drilling. Field observations of Upper Devonian shale-hosted concretion dimensions suggest that Marcellus-hosted concretions up to three feet in length are possible. Hiatuses in sedimentation and potential concretion horizons were predicted using uranium to organic carbon ratios. The attachment of uranium to organic carbon macerals occurs across the sediment-water interface. Therefore, an increase in the abundance of uranium per unit organic carbon indicates a cessation in sedimentation and the potential for concretion growth. Indeed, when comparing well log response to core, uranium to organic carbon excursions predicted the location of two concretion horizons.
Production from organic-rich shale petroleum systems is extremely challenging due to the complex rock and flow characteristics. An accurate characterization of shale reservoir rock properties would positively impact hydrocarbon exploration and production planning. We integrate large-scale geologic components with small-scale petrophysical rock properties to categorize distinct rock types in low porosity and low permeability shales. We then use this workflow to distinguish three rock types in the reservoir interval of the Niobrara shale in the Denver Basin of the United States: The Upper Chalks (A, B, and C Chalk), the Marls (A, B, and C Marl), and the Lower Chalks (D Chalk and Fort Hays Limestone). In our study area, we find that the Upper Chalk has better reservoir-rock quality, moderate source-rock potential, stiffer rocks, and a higher fraction of compliant micro- and nanopores. On the other hand, the Marls have moderate reservoir-rock quality, and a higher source rock potential. Both the Upper Chalks and the Marls should have major economic potentials. The Lower Chalk has higher porosity and a higher fraction of micro-and nanopores; however, it exhibits poor source rock potential. The measured core data indicates large mineralogy, organic-richness, and porosity heterogeneities throughout the Niobrara interval at all scale.
Unconventional petroleum systems are highly complex hydrocarbon resource plays both at the reservoir scale and at the pore scale (Aplin and Macquaker, 2011; Loucks et al., 2012; Hart et al., 2013; Hackley and Cardott, 2016). These organic-rich sedimentary plays, generally described as shale reservoirs, are composed of very fine silt-and clay-sized particles with grain sizes < 62.5 μm (Loucks et al., 2009; Nichols, 2009; Passey et al., 2010; Kuila et al., 2014; Saidian et al., 2014). They undergo extensive post-depositional diagenesis that transforms rock composition and texture, hydrocarbon storage and productivity, and reservoir flow features (Rushing et al., 2008; McCarthy et al., 2011; Jarvie, 2012; Milliken et al., 2012). Although some shale rock facies can retain depositional attributes during diagenesis, many critical reservoir properties, such as, mineralogy, pore structure, organic richness and present-day organic potential, etc., are significantly perturbed (Hackley and Cardott, 2016).
We studied the Vaca Muerta (VM) Play (Neuquén Basin, Argentina) focusing on an oil window mature well (VR ~0.9-1.1%) to determine 1) zones of enrichment and depletion, 2) correlation/allocation to produced fluids, and 3) in-situ GOR and PVT characteristics.
Zones of saturation versus depletion, total in-place liquids, oil quality and bitumen enrichment throughout the Upper (U-), Middle (M-), and Lower (L-) VM were documented using screening methods such as Rock-Eval, TOC, thermovaporisation and pyrolysis gas chromatography on 24 original whole rock samples as well as solvent extracted aliquots. For production allocation and API prediction produced fluids were analysed in comparison to extracts from the shale units using whole oil chromatography and stable carbon isotope as well as high resolution mass spectrometry (FT-ICR MS). For prediction of GOR and PVT characteristics a combination of MSSV-pyrolysis and PVT modelling was used in the PhaseKinetics approach (di Primio and Horsfield, 2006) for immature samples and in the PhaseSnapShot approach (Kuske et al., 2019) for matured samples.
Especially the methods and experimental protocols used for the predictive assessments (FT-ICR MS; MSSV) are novel, unique, and strongly improve our ability to correctly describe the effects of production fractionation on bulk fluid properties and hence to formulate appropriate production strategies. In general, this study excels by combining results from organic geochemistry with those of PVT modeling and analysis.
Gas production from shale formations is growing, especially in the USA. However, the origin of shale gases remains poorly understood. The objective of this study is to interpret the origin of shale gases from around the world using recently revised gas genetic diagrams. We collected a large dataset of gas samples recovered from shale formations around the world and interpreted the origin of shale gases using recently revised gas genetic diagrams. The dataset includes >2000 gas samples from the USA, China, Canada, Saudi Arabia, Australia, Sweden, Poland, Argentina, United Kingdom and France. Both free gases collected at wellheads and desorbed gases from cores are included in the dataset. Shale gas samples come from >34 sedimentary basins and >65 different shale formations (plays) ranging in age from Proterozoic (Kyalla and Velkerri Formations, Australia) to Miocene (Monterey Formation, USA). The original data were presented in >80 publications and reports. We plotted molecular and isotopic properties of shale gases on the revised genetic diagrams and determined the origin of shale gases. Based on the distribution of shale gases within the genetic diagram of δ13C of methane (C1) versus C1/(C2+C3), most shale gases appear to have thermogenic origin. The majority of these thermogenic gases are late-mature (e.g., Marcellus Formation, USA and Wufeng-Longmaxi Formation, China) and mid-mature (associated with oil generation, e.g., Eagle Ford Formation, USA). Importantly, shales may contain early-mature thermogenic gases rarely found in conventional accumulations (e.g., T⊘yen Formation, Sweden and Colorado Formation, Canada). Some shale gases have secondary microbial origin, i.e., they originated from anaerobic biodegradation of oils. For example, gases from New Albany Formation and Antrim Formation (USA) have secondary microbial origin. Relatively few shale gases have primary microbial origin, and they often have some minor admixture of thermogenic gas (e.g., Nicolet Formation, Canada and Alum Formation, Sweden). Two other revised gas genetic plots based on δ2H and δ13C of methane and δ13C of CO2 support and enhance the above interpretation. Although shales that contain secondary microbial gas can be productive (e.g., New Albany Formation, USA), the resource-rich, highly productive and commercially successful shale plays contain thermogenic gas. Plays with late-mature thermogenic gas (e.g., Marcellus Formation, USA and Wufeng-Longmaxi Formation, China) appear to be most productive.
The expansion of unconventional petroleum resource exploration and production in the United States has led to an increase in source rock characterization efforts, particularly related to bulk organic and mineralogical properties. To support the analytical and research needs of industry and academia, as well as internal work, the U.S. Geological Survey (USGS) has collected and prepared shale geochemical reference materials (GRMs) from several major shale petroleum systems in the U.S. The sources of these materials are the Late Cretaceous Boquillas (lower Eagle Ford-equivalent) Formation (roadcut near Del Rio, TX), Late Cretaceous Mancos Shale (outcrop near Delta, CO), Devonian–Mississippian Woodford Shale (outcrop near Ardmore, OK), Late Cretaceous Niobrara Formation (quarry near Lyons, CO), Middle Devonian Marcellus Shale (creek bed in LeRoy, NY), and Eocene Mahogany zone oil shale of the Green River Formation (oil shale mine near Rifle, CO). Of particular interest in the development of these GRMs has been the examination of variability between laboratories and specific methods or instruments in commonly made measurements, including major- and trace-element concentrations, X-ray diffraction (XRD) mineralogy, total organic carbon (TOC) content, and programmed pyrolysis (PP) parameters. For the component concentrations and parameters we measured, the techniques and instrument types included: (1) elemental analysis by X-ray fluorescence, inductively coupled plasma mass spectrometry, and instrumental neutron activation analysis; (2) XRD mineralogy with various preparatory methods (spray drying or micronizing with or without internal standard); (3) TOC by combustion with infrared detection after carbonate removal or the PP approach; (4) PP by Rock-Eval 2 or more recently developed instruments (Rock-Eval 6, Source Rock Analyzer or SRA, and Hydrocarbon Analyzer With Kinetics or HAWK). Overall, the results showed that the selected shales cover a wide range of source rock organic and mineralogical properties. Major- and trace-element chemistry results showed low heterogeneity consistent with other USGS GRMs. Comparison of TOC results showed coefficients of variation (COV) of around 5% and the most consistent organic geochemical results between different laboratories and methods. Arguably the most relevant PP measurement, S2 or kerogen hydrocarbon-generating potential (mg-HC/g-rock), showed a somewhat wider range of variability than TOC (COV ~10%), but was consistent between the three modern instruments and the industry-standard Rock-Eval 2. Major phase mineralogy (mineral concentrations ≥10 wt. %, organic-free basis) were comparable between laboratories, but variability in minor phase identification and quantification was observed. Utilization of these shale GRMs as quality control samples and testing materials is expected to help support analytical and experimental efforts in the continued development of unconventional petroleum resources.
Shale has been a major destination for unconventional hydrocarbon resources for its wide stratigraphic coverage as well as high volumetric hydrocarbon potential. Contemporary success in North American shale plays has intrigued operators worldwide in shale exploration. Organic richness has been a key factor to determine the potential of shale as it is proportional to the amount of hydrocarbon likely to be generated and stored in available spaces within the shale. The other important factor in this context is shale brittleness as it indicates how fracable the potential shale is. Attempts are made here by strategically using standard wireline logs in order to evaluate potential of Eocene Vadaparru Shale in Krishna Godavari Basin, India qualitatively and quantitatively.
The technique used in this study involves identification of organic lean ‘clean shale’ interval and establishing a ‘clean shale’ relation of resistivity as a function of compressional sonic transit time in the study wells, as both the logs respond comparably to shale and its organic content. Using this relation a proxy ‘clean shale’ resistivity log is generated in shale and compared with measured wireline resistivity. A positive separation between calculated and measured resistivity is then assessed as proportionate shale organic richness, owing to the presence of relatively less dense (corresponding to longer sonic transit time) and more resistive organic content. Shale brittleness is predicted from Young's modulus and Poisson's ratio using compressional, shear and Stoneley wave velocities obtained from sonic measurements, assuming transversely isotropic nature of Vadaparru Shale.
The Eocene marine transgressive Vadaparru Shale is a dominant stratigraphy in KG basin as evident from seismics and drilling. Petrophysical analyses in study wells indicated appreciable brittleness within Vadaparru Shale. The organic richness i.e. amount of positive separation between calculated and measured resistivity combined with brittleness quantitatively indicate fair to excellent unconventional potential of Vadaparru Shale. Considerable thickness, Type-II, III kerogen content and geochemical measurements support the study and highlight it as a promising ‘shale reservoir’ destination. In the context of rapidly growing energy demand of India Vadaparru Shale can be considered as serious unconventional player.
Overall this study presents quick strategy for shale potential quantification, thus allowing operators to focus spatially in the quest of unconventional hydrocarbon resources.
Models for steam or hot-water injection into a fractured diatomite or shale reservoir are developed from existing analytic models of energy transport and countercurrent imbibition.
Radial convective heat flow through a horizontal fracture system is modeled with conductive heat flow into the low-permeability matrix. The flow geometry approximates hot-fluid injection into a five-spot pattern. Recovery mechanisms accounted for in the models include capillary imbibition and thermal expansion. Temperature dependence of viscosity and interfacial tension (IFT) are included in the imbibition estimate. Laboratory data are needed to quantify the magnitude of the imbibition mechanism, which is usually the primary contributor to oil recovery. Reservoir properties representative of either the Belridge Diatomite or the Antelope Shale, two giant fractured oil reservoirs, are used for the model forecasts. Currently, however, only temperature-dependent imbibition data for diatomite reservoirs are available.
The steamflood model has been partially validated against a large-scale project in the Belridge Diatomite. By use of public-domain information, a reasonable comparison was obtained between the model and the field project during a 4-year injection period. Comparison with conventional thermal simulation was also performed, and it indicated reasonable agreement with the steamflood analytical model.
The models have been used to determine the key factors determining the success of thermal recovery in fractured, low-permeability reservoirs. Steam injection is shown to be superior to hot-water injection in heating the matrix. Key factors enhancing recovery include reduced fracture spacing, increased matrix permeability, and increased injection temperature. Model results indicate that steamflood recoveries of more than 40% of the original oil in place (OOIP) may be achieved by injection in diatomite containing light oil. Application to diatomites containing heavy oil also shows good performance. Successful application in diatomite reservoirs is forecast to be possible in the current low oil-price environment. Economic application in fractured shales, assuming similar imbibition behavior as in diatomites, would require a higher oil price because of the higher well costs and lower oil content relative to diatomite projects.
Because of the significant volumes of remaining oil in place (OIP) in both the diatomite and shale reservoirs, the application of thermal enhanced oil recovery (EOR) to these resources represents the logical next step in steamflood development.
Saini, Dayanand (California State University, Bakersfield) | Wright, Jacob (California State University, Bakersfield) | Mantas, Megan (California State University, Bakersfield) | Gomes, Charles (California State University, Bakersfield)
A critical analysis of the key geological characteristics, completion techniques, and production behaviors of the Monterey Shale wells and their comparisons with analogous major US shale plays—namely, the Bakken and the Eagle Ford—may provide insights that could eventually help the petroleum industry unlock its full potential. The present study reports on such efforts.
The Monterey Shale is very young and geologically heterogeneous compared with the Eagle Ford and the Bakken. Oil viscosity in the Monterey Shale is significantly higher, and one can also notice that Monterey oil production has declined over the years. The Monterey Shale has a field-dependent completion strategy (pattern spacing and fracturing stage), while a horizontal, uncemented wellbore completion is common in the Bakken and the Eagle Ford. In the Monterey, nonhydraulically fractured zones of horizontal and hydraulically fractured wells appear to be making approximately equal contributions to the well’s cumulative production. The ongoing water-disposal operations in overlying injection zones, up to a certain extent, have affected the productivity of both types (long and short production histories) of wells. The geology also appears to have an effect on the production behaviors of horizontal and hydraulically fractured wells.
A preliminary economic analysis suggests that exploitation of the Monterey Shale is still a profitable venture. However, for sustainable development in a current price regime of USD 50/bbl of crude oil, it is necessary that production costs be reduced further. Also, compared with the Bakken and the Eagle Ford, the Monterey sits in regions of extremely high water stress (i.e., frequent occurrences of drought or drought-like conditions). However, oilfield-produced water associated with current steamflooding-based oil- and gas-production operations in the region as a base fluid suggests that it can potentially meet most of the water demand for future fracturing jobs. Also, combined use of a centralized water-management system; a less-costly, more energy-efficient, and high-capacity solar-powered desalination system; and a final sludge-management and/or residual-brine-disposal mechanism might assist the petroleum industry in managing flowback and produced waters while keeping water-handling costs low.
A combination of new enhanced-oil-recovery (EOR) methods for releasing the remaining oil from both nonfractured and fractured zones of horizontal wells and the use of oilfield-produced and recycled water for completing hydraulically fractured horizontal wells might prove to be a significant change for the future exploitation of California’s Monterey Shale resource, which is subject to the toughest hydraulic-fracturing regulations in the nation and is in a region of extremely high water stress.
O'Brien, William J. (Nitec LLC) | Moore, R. Gordon (University of Calgary) | Mehta, Sudarshan A. (University of Calgary) | Ursenbach, Matthew G. (University of Calgary) | Kuhlman, Myron I. (MK Tech Solutions)
This paper outlines the results of an early-stage comparative study of air-injection-based and immiscible-carbon-dioxide (CO2)/water-injection-based enhanced-oil-recovery (EOR) processes for a 30+ °API tight, light-oil reservoir. This was accomplished by embedding multiple low-permeability core plugs in crushed reservoir-core material to create a composite core that was contained in a 1.84-m-long core holder. The objectives of this unscaled experimental work were to understand the suitability of each EOR process for a low-permeability reservoir; to define process parameters before a potential field pilot; and to understand the relative merits of each EOR process to mobilize light oil from a tight matrix to a fracture network.
A detailed experimental investigation was conducted at realistic reservoir conditions to evaluate the feasibility of an air-injection-based EOR process. The air-injection results were compared with those from an immiscible CO2/water-injection EOR experiment using the same experimental setup and reservoir conditions. Both the air- and CO2/water-coreflood tests were performed at 10 340 kPag (1,500 psig) and 99°C in a 100-mm diameter, 1.84-m-long composite-core holder using 38-mm-diameter reservoir core plugs (that represented the matrix) mounted within the crushed reservoir-core material (that represented the fracture); inert helium gas was used to pressure up the core holder to reservoir pressure. Permeability of the core plugs was from 0.3 to 3 md, while the permeability of the crushed core material was 1 to 3 darcies.
Air injection was performed as a standard, one-dimensional combustion-tube test with injection of 2.3 pore volumes (PVs) of air to burn 71% of the packed core length (including helium, a total of 4.3 PV of gas injected). The CO2/water coreflood was performed with the injection of 2.86 PV of CO2 followed by an extended soak period, then a second injection of an additional 2.86 PV of CO2, followed by the injection of 2.6 PV of water.
The pretest and post-test core-plug measurements of oil saturation show that the air-injection process removed significantly larger quantities of hydrocarbons than the immiscible-CO2/water-injection process. Relative to the initial conditions of the core plugs for the air-injection experiment, more than 95% of the hydrocarbons were removed (note that some fraction of original oil was consumed as fuel). In the post-test CO2/water-injection core plugs, oil recovery was in the range of 30 to 55% of initial oil in place (IOIP). These findings suggest that, under an appropriate field design, both processes have the potential to recover incremental oil from tight reservoirs. However, the air-injection process might be better suited to mobilize oil, because of thermal expansion, than the CO2/waterflood process.