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Chiotoroiu, Maria-Magdalena (OMV E&P) | Clemens, Torsten (OMV E&P) | Zechner, Markus (OMV E&P) | Hwang, Jongsoo (University of Texas at Austin) | Sharma, Mukul M. (University of Texas at Austin) | Thiele, Marco (Streamsim)
Summary Waterflooding can lead to substantial incremental oil production. Implementation of water-injection projects requires the project to fit into the risk (defined here as negative outcomes relative to defined project objectives) and uncertainty (defined here as the inability to estimate a value precisely) a company is willing to take. One of the key risks for water injection into a shallow reservoir is injection-induced fractures extending into the caprock. In this study, we evaluated caprock integrity by conducting simulations of long-term water injection that include the effects of formation damage caused by internal/external plugging, geomechanical stress changes, and fracture propagation in the sandstone and bounding shale. The risk of fracture growth into the caprock was assessed by conducting Latin hypercube sampling considering a set of modeling parameters each associated with an uncertainty range. This allowed us to identify the range of operating parameters in which the risk of fracture-height growth was acceptable. Our simulations also allowed us to identify important factors that affect caprock integrity. To cover the uncertainty in geomechanical reservoir evaluation, the operating envelope is identified such that the risk to the caprock integrity is reduced. This requires introducing a limit for the bottomhole pressure (BHP), including a safety margin. The limit of the BHP is then used as a constraint in the uncertainty analysis of water injectivity. The uncertainty analysis should cover the various development options, the parameterization of the model, sampling from the distribution of parameters-and distancebased generalized sensitivity analysis (dGSA) as well as probabilistic representation of the results. The results indicate that the time to reach the BHP limit varies substantially, dependent on the chosen development scenario.
The goal of this research is to study the structural integrity and slot width change of slotted liners by comparing them with a 3D finite element analysis and experimental study. Slotted liners are widely used because of their ability to ensure wellbore integrity and sand control. During installation and operations, the slotted liners must be strong enough to hold axial loads and radial compression to prevent excessive buckling and deformation of slots. Laboratory collapse and bending tests were conducted with commercially available slotted liners. Experiments were designed to select the grades of materials, diameter/thickness of pipes, and slot patterns. Finite element models were developed to predict the integrity of slotted liners and acceptable slot width changes. The study considered slotted liner design and analyzed how much material grades, casing/tubing dimension, and slot patterns affect the risk of slotted liner failure. The practical implications of this work to the oil fields are (1) a numerical simulation model can predict the closure of slots with reasonable accuracy if the work hardening stress-strain curve after elastic limit is accurately input; therefore, we may select the slotted liner design with sufficient stability after installation, and (2) the strength gains due to work hardening are significantly larger for a lower-grade base pipe than a higher-grade base pipe. Therefore, we need to re-evaluate using a lower-grade base pipe before using a thinner high-grade base pipe for some applications.
An intrashelf depo-center hosts the Jurassic carbonate source rock, which contains one of the richest hydrocarbon producing source rock intervals in the world. The understanding of kerogen distribution and maturity across this frontier unconventional basin is key for focused prospectivity and future development. A correlation between total organic carbon (TOC) and porosity and key reservoir parameters has been observed. The porosity, measured using the Gas Research Institute (GRI) methodology, shows a poor TOC values correlation, as measured by LECO. A substantial amount of liquid hydrocarbon has been recorded during pyrolysis in the S1 peak, constituting a significant portion of the measured TOC. This effect has to be quantified in order to avoid issues when calibrating logs to predict TOC, saturation and porosity.
An analytical workflow was developed to remove the free hydrocarbon and bitumen from samples. Each sample was split into two parts; and sent for LECO-TOC and SRA pyrolysis. The initial run was conducted using an industry standard sample preparation method. In the second run, sample preparation included a solvent extraction. An organic solvent was used to remove the free hydrocarbons and mobile bitumen, thus taking off the S1 and oil shouldering effects on the S2 emission peak on the pyrograms. The two resulting data sets were then compared, and showed a net reduction of TOC in addition to increasing in Tmax values for most of the post-extraction samples.
Results of this detailed analysis yielded a new set of thermal maturity values. Furthermore, log-derived TOC calculations have been recalibrated resulting in a more accurate petrophysical model. These corrections generated more reliable results that greatly enhanced our understanding of basin maturity variations and organic matter distribution; thus decreasing uncertainty and refining in-place resource estimations across the basin.
The history of California’s oil business is long and checkered. The first Californian well was drilled in 1865 in Humboldt County (Am. The state’s first gusher arrived in 1876 in the Pico Canyon oil field located north of Los Angeles and launched a statewide industry (Figure 1A) (oilindependents.org). The early success led to a drilling rush, which spawned supporting industries such as pipeline construction (California’s first was built in 1877) and crude oil refining (California’s first refinery opened in 1880) (AOGHS, 2019). Following the initial oil discovery in California, Edward L. Doheny struck the massive Los Angeles oilfield in 1892, only 35 miles south of the Pico Canyon (Figure 1B) (oilindependents.org,
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.
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.
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.
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).
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.
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.