Almost simultaneously, advances were made in understanding both the processes within the source rock organic matter that accompany the generation and expulsion of hydrocarbons and in the acquisition, processing, and quantitative interpretation of 3D seismic data. In particular, as organic matter in shales in unconventional plays generates and expels hydrocarbons, porosity is formed in the organic matter and the organic matter becomes more dense and more brittle. As these changes are occurring at a micro-scale, extraction of hundreds of different attributes from a well-imaged 3D seismic volume has made it possible to observe changes at a macro-scale in seismic lines and horizons within that volume. Seismic attributes derived from pre-stack inversions yielding rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density, when calibrated with well log and/or core measurements, can be combined to calculate TOC, pore pressure, rigidity, and compressibility because these properties cause fundamental changes in how seismic waves travel through the rock.
Equally important, the escalation in computing power via methods such as machine learning, neural networks, and multivariate statistics has made it possible to interpret large amounts of data. All of these innovations have contributed to better identification of sweet spots within unconventional plays. Such sweet spots include areas with elevated TOC values, enhanced porosity, and zones that can be targeted for fracking.
One of the primary advantages of seismic data is that it provides information in those areas in between control points/wells. This information in turn helps operators to better select targets for wells and for landing zones. Carefully tied 3D seismic inversion and integration with petrophysical and rock data further allow for detailed characterization of unconventional reservoirs. The enhanced ability to identify the best potential drilling targets has significant economic implications in terms of risk reduction and improved chances to find economic prospects.
While 3D seismic data is being used routinely by numerous companies to predict the mechanical properties, density, and associated TOC of many formations, there is yet to be a direct link made between TOC loss, kerogen conversion, and the associated changes in rock properties. This work documents the importance of TOC loss during maturation and its effects on rock properties like porosity, density, brittleness, and how those advances coupled with the advances in quantitative interpretation of 3D seismic data are enabling the unconventional operators to predict location, thickness, landing zone, and sweet spots with appropriately acquired, processed, and interpreted 3D seismic. Meticulously calibrated 3D seismic inversion and integration with petrophysical and rock data permit detailed reservoir characterization of unconventional reservoirs.
Updated methods for the back calculation of original TOC have been developed using well logs, rock measurements, and 3D basin modeling to assist in locating and developing unconventional reservoirs. In addition, petrophysical measurements that reflect TOC and porosity and are related to fundamental properties controlling the seismic response can be extracted from the seismic reflection data. In turn, seismic attributes derived from pre-stack inversions yielding rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density, when calibrated with well log and/or core measurements, can be combined to estimate TOC, pore pressure, rigidity, and compressibility because these properties cause basic modifications in how seismic waves travel through the rock.
This study shows advancements in studies of: 1) TOC loss with increased thermal maturation, 2) how this loss affects the development of organic porosity, 3) how kerogen becomes denser, harder, and more brittle with increasing maturity, and 4) how recent developments in quantitative interpretation workflows for 3D seismic data facilitate estimation of TOC and determination of rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density. Further integration of geochemical, geomechanical, and geophysical technologies and measurements will provide improved estimates of present-day TOC that can in turn be extended to relative maturity and percent conversion.
Examples provided in this work illustrate prediction of present-day TOC, porosity, density, and mechanical properties extracted from high fidelity pre-stack inversion. Pre-stack inversion along with machine learning can be used to predict rock properties such as porosity, TOC, organic matter quality, rigidity, and pressure and to correlate those properties back to well productivity for improved execution. Relating present TOC estimated from seismic to TOC loss and kerogen property changes with increasing maturity is possible by combining the results of these technologies.
Though analysis and inversion of painstakingly acquired modern 3D seismic data is capable of estimating porosity, TOC, matrix strength, and pore pressure, the latest work on rock property changes as hydrocarbons mature and are expelled isn't typically addressed in most studies. Increasing communication between disciplines might improve estimation of these properties and extend the capability to assess the extent of TOC loss during maturation and the porosity increases that accompany it. This ability is especially important in the intra-well regions where the potential of 3D seismic to extend data between control points enables better reserve estimates and high grading of acreage. After carefully calibrating a quantitative 3D seismic interpretation with a 3D basin modeling analysis of the source rock potential and maturity, an operator is better prepared to high grade acreage and attain the most economic development of unconventional resources.
The escalation in computing power means there are hundreds of different attributes that can be extracted or calculated from a well-imaged 3D seismic volume. Using quantitative calibration of fundamental geochemical measurements such as TOC, pyrolysis, and petrographic measurements of vitrinite reflectance that yield the quantity, quality, and maturity of organic matter in combination with well log and seismic data creates a model for identifying sweet spots and the areas in the target formation that exhibit high TOC, high porosity, and elevated brittleness. Further integration and calibration of changes occurring at the micro-level in organic matter in unconventional plays with their impact on the signatures of data at the macro-level can provide information on the types of hydrocarbons most likely to be found in these sweet spots as well as identifying which zone(s) in the target formation are most likely to be amenable to fracking. Used together, the advances outlined here result in a technological evolution that could have a substantial impact on: 1) the approach to and 2) the economics of the exploration and production of unconventional plays.
A new approach that uses logs derived from wireline and surface drilling data to extract an interface proxy is presented and illustrated in the Montney. The derived interface proxy logs are propagated in the entire reservoir volume using artificial intelligence-based reservoir modeling. Blind wells confirm the ability to predict the interface proxy at any reservoir location. The derived interface proxy propagated in 3D was validated with moment tensor showing that the microseismic shear plane events occur mainly where the presence of the interfaces is the highest.
Using the derived interface proxy as an input, the Material Point Method (MPM) and Anisotropic Damage Mechanics (ADaM) are used to solve the geomechanical modeling of a hydraulic fracture propagating in a layered medium containing any type of interfaces including the weak interfaces. The geomechanical simulation confirms the major impact these weak interfaces could have on the fracture height growth.
The geomechanical analysis confirmed the importance of mapping in 3D the interfaces and modeling their effects in an accurate manner to better capture their effect on fracture height growth and the resulting proppant placement. The application of the new geomechanical workflow was illustrated on two Montney wells and was able to provide some explanation on their production differences that could be attributed to interfaces.
There is an ongoing paradigm shift in the processes and technologies employed in making field development decisions in unconventional reservoirs. Expensive trial and error exercises in multiple reservoirs have returned the verdict: there is no single prescribed treatment for a given reservoir, which always maximizes production and eliminates risk of frac hits and well interferences. In many situations, lateral growth of hydraulic fractures has been the major concern amongst operators, but as the economics of unconventional production shift, and the industry moves to more wine-racking and cube development plans, it has become abundantly clear that current hydraulic fracturing design software have multiple shortcomings such as not being able to fully account for natural fractures and predicting the subsequent frac-complexity as well as including the critical effects of weak interfaces. One of the consequences of this poor representation of the physics occurring during hydraulic fracturing of unconventional wells is the overprediction of hydraulic fracture heights. All commonly used industry frac design software are neither able to predict microseismicity to prove their ability to reproduce the observed frac complexity nor capable of including the effects of weak interfaces, or bedding and laminations (geologically speaking) on hydraulic fracture propagations in the vertical direction. Since microseismicity has been successfully predicted to capture the lateral stress gradients created by the natural fractures, the focus in this study is quantifying at any well the characteristics of the interfaces and their impact on the fracture height. Geomechanical logs derived from commonly available surface drilling data are used to capture zones of high interface potential and their characteristics. The resulting interface positions and their mechanical properties are input in a geomechanical simulator using the Material Point Method (MPM) to simulate the effect of the weak interfaces on hydraulic fracture height growth. These simulations provide the necessary information required by frac design software that now can incorporate not only the lateral stress gradients created by the natural fractures but also the vertical complex effects created by the weak interfaces. The results of this fast-practical decoupled workflow are a better estimate of the spacing needed for wine-rack systems and more realistic fracture geometries inputs to fluid flow models which can provide realistic geometries of depletion profiles affecting well interference potentials driven by production.
Objectives/Scope: The continuous drive by the E&P industry to deliver additional value and performance improvements in unconventional reservoirs has created the need for innovative advances in technology to meet evolving challenges. Jweda et al. (2017) and Liu et al. (2017) developed a novel time-lapse geochemistry technology calibrated to core extracted oils to cost effectively ascertain vertical drainage, which is among the most critical parameters used in determining optimal field development strategies. Aqueous geochemistry, well-established in academic and environmental investigations, is another technology that can be used in conjunction with time-lapse hydrocarbon geochemistry to evaluate drainage behavior, vertical connectivity between stacked wells and to ascertain the efficacy of different stimulation designs. Methods/Procedures/Process: More than 300 produced water samples from approximately 60 different Eagle Ford wells have been collected across ConocoPhillips’ Eagle Ford acreage. Sampling campaigns have included collecting several long-term time-series and baseline samples from individual wells across the field. The analytical program consists of a suite of total ion chemistry (cations and anions), salinity, alkalinity, and isotopic geochemistry (δ18O, δD, 87Sr/86Sr, δ11B). Results/Observations/Conclusions: Produced waters, contain a robust arsenal of geochemical signals that can be analyzed to understand the provenance(s) and change(s) in composition with time of these produced waters. A combination of interpretative and multivariate statistical tools were used to gain a deeper understanding of water-rock interactions and mixing/diffusion processes in the subsurface. Stimulation water was differentiated from in-situ formation water, and the evolution of that process was tracked over time. Time-series water analyses were also used to evaluate differences between completion designs, determine the vertical drainage and/or communication between wells, and ultimately understand the drained rock volume through time. Applications/Significance/Novelty: We clearly demonstrate that produced waters are mixtures of stimulation and formation water and that long-term geochemical signals from different layers within the Eagle Ford can be differentiated using aqueous geochemistry. Furthermore, we show that the formation waters vary vertically, coincident with hydrocarbon indicators (oil biomarkers and gas isotopes). To our knowledge, this is among the first published studies of aqueous geochemical behavior of produced waters in the Eagle Ford and the first to establish that intra-formational waters can be discerned, which is particularly novel and important for evaluating completion designs and strategies within a stacked development.
Publicly-available fault data for the Delaware basin is used to simulate a detailed map of maximum stress direction at a scale of 1000ft x 1000ft throughout the Delaware basin. The resulting maps highlight the complexity of stress fields in the Delaware basin and the importance of accounting for the interaction of entire fault systems with regional stresses. This underscores a dire need for the industry to better quantify structural features in and around unconventional reservoirs. When commercially-available seismic data is used for a refined interpretation of the structural features that affect the stress field, geomechanical models can be refined to provide valuable information at the well and pad scale to influence and optimize well spacing and completion decisions to minimize frac hits and other undesirable well interferences. Multiple data collected at the wells are used to validate the predicted stress orientation and their impact on the performance of hydraulic fracturing jobs. These results were enabled by the use of validated geomechanical modeling that is able to easily handle the faults and natural fractures. This is implemented by using the material point method to address the computational challenges introduced by the presence of these earth discontinuities in the general continuum mechanics equations representing the static and dynamic variations of stress in unconventional reservoirs.
Production of unconventional wells is dictated by both the geological (resource) and geomechanical (recoverability) properties of the reservoir. The geomechanics of a reservoir can be broken down into the rock mechanical properties, which near the wellbore primarily control fracture initiation potential, and the current stress state, which away from the wellbore controls the propagation of successfully induced hydraulic fractures and their interaction with natural fractures and layer interfaces. The consequential properties of the stress state can be further refined and represented as the differential stresses and the maximum horizontal stress orientation. In the Permian basin where a normal fault regime is common, it is critical that an unconventional horizontal well be drilled nearly perpendicular to the maximum horizontal stress direction (MHSD) in order to induce transverse hydraulic fractures and thereby maximize its stimulated reservoir volume (SRV). Additionally, maximum horizontal stress orientation is a major control on fault stability and a primary concern when quantifying the induced seismicity potential in a given area. Stress rotations have been documented at regional, basin, field, and pad scales (Umholtz & Ouenes, 2015, Umholtz & Ouenes, 2016, Ouenes et al., 2016). What cannot be ignored, is the reciprocal relationship between fault networks and stress fields. While fault quantification is readily available at field scales (when seismic data exists), operators rarely disclose these interpretations to be used in comprehensive regional studies. This study will initially focus on quantifying stress rotations at basin and county scales using publicly-available data, and further refine these estimates by integrating interpreted fault information from readily-available seismic data.
Kumar, Abhash (National Energy Technology Laboratory / Leidos Research Support Team) | Hu, Hongru (University of Houston) | Bear, Alex (National Energy Technology Laboratory) | Hammack, Richard (National Energy Technology Laboratory) | Harbert, William (National Energy Technology Laboratory / University of Pittsburgh)
Hydraulic fracturing involves the injection of large amount of fluid, typically water, in the reservoir rock that increases fluid pressure in the pore spaces and alters the stress condition of the rock significantly. This sudden change in the stress condition is strong enough to create new fractures in the rock or stimulates slip along the pre-existing fractures. Creating new fractures or inducing slip along multiple pre-existing fractures, both results into a marked increase in the interconnectivity of pore spaces and enhance the flow of oil and gas within the stimulated volume. The distribution of microseismic earthquakes that are generated during hydraulic fracturing is traditionally used as a proxy to estimate stimulated reservoir volume (SRV). For efficient extraction of oil and natural gas, it is extremely important to get an accurate estimate of the SRV. However, a simple energy balance calculation suggests that the combined energy released from all microseismic earthquakes during hydraulic fracturing is a small portion of the total input energy, supplied to the reservoir rock in the form of injected fluid. The difference in the total input and output energy suggests some alternate mechanism of deformation in the reservoir rock during hydraulic fracturing that need to be considered to get more accurate estimate of the total stimulated reservoir volume. Recent studies of hydraulic fracturing in the Barnett Shale, Marcellus Shale, Eagle Ford Shale and Montney Shale found the evidence of low-frequency events, with drastically different seismic signature (frequency, amplitude, time duration) than traditional microseismic earthquakes. These low frequency (1-80 Hz) earthquakes are proposed to be associated with either jerky opening or slow rate of slip along pre-existing fractures that are unfavorably oriented in the ambient stress field and releasing as much as 1000 times the energy of an average microseismic earthquake.
We identified multiple long period long duration (LPLD) earthquakes in the surface seismic data recorded during hydraulic fracturing of the two Middle Wolfcamp Shale wells in Reagan County (RC), TX. LPLD events identified in this study show a dominant P-wave signal that persists for 5-10 seconds and significantly long duration compared to traditional microseismic events. We also noticed finite decay in seismic amplitude across the surface-monitoring array suggesting a non-regional or local source of deformation for their origin. We aim to compare and contrast our surface seismic observations on LPLD with seismic data from two 24-tool borehole arrays that were deployed in vertical section of the two nearby treatment wells. This comparison between surface and borehole data will be of strategic importance to evaluate the efficiency of surface seismic monitoring and it would also be helpful in finding more LPLD events in borehole data that are usually less contaminated with the surface noise.
Connectivity of the pore system is crucial for production of hydrocarbons from unconventional resources. In shales, pore throats critically control and limit permeability. Even if larger pores are the dominant pore size, small pores throats could ultimately control the access to that pore space. Mercury injection capillary pressure (MICP) measurements are commonly made to determine pore throat size distributions. Results for shales usually show large injection volumes associated with pore throats just several nanometers in diameter. The existence of these small pore throats has also been confirmed by Focused Ion Beam/Scanning Electron Microscope (FIB/SEM) analysis. One of the unique properties of mercury is that it is non-wetting to both matrix phases present in organic-rich shales; therefore, it can access pore systems in both organics and inorganics. MICP measurements dynamically alter the pore structure through pore compressibility which intrinsically depends on the aspect ratios of the pores; crack like pores, with very high aspect ratios, may close at low pressures and may not be sampled by MICP. The connectivity of the pore space and how much of it is accessed by MICP remains poorly understood.
Here we report on shale samples that have undergone MICP followed by Micro X-ray Computed Tomography (μXCT) and FIB/SEM imaging. μXCT results show that not all regions of the shale samples were accessed uniformly by MICP. Mercury is observed going into fractures and penetrating into the shale matrix. The distance away from the fractures and the percentage of the sample volume accessed by mercury has been calculated. Some samples, such as the Tuscaloosa Marine Shale, showed mercury penetration throughout specific layers in the sample, whereas Eagle Ford samples showed mercury penetration more uniformly and on average of almost 150 μm away from the fractures with almost 60% of the entire sample volume accessed by the mercury. These μXCT results suggest that mercury is not fully accessing all the pore space of the sample even at 60,000 psi which corresponds to a pore throat radius of 1.8 nm.
Cryo FIB/SEM was used to further investigate mercury intrusion into the shale matrix at the nanometer scale. Frozen droplets of mercury were observed in pores as small as 30 nm which corresponds to an injection pressure of 6,000 psi. The mercury clearly accessed the organic pores and remained after pressure was reduced. This is also reflected in the hysteresis observed in the MICP spectra captured during pressurization and depressurization. The magnitude of the hysteresis is a consequence of the differences between pore bodies and pore throats. Like the μXCT, SEM results show that intrusion of mercury into the sample is not uniform indicating that many of the pores are not connected to the outside of the sample. These results suggest that pore connectivity in shales may be very limited, and the volume accessible may not extend far from fractures in the shales.
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.
Fisher, Aaron (Tracker Resource Development) | O'Keefe, F. X. (Tracker Resource Development) | Niedz, Chris (Tracker Resource Development) | Wehner, Brian (Tracker Resource Development) | Kramer, Nick (Apex Petroleum Engineering) | Heuermann, Paul (Apex Petroleum Engineering) | Patrick, Scott (Fracture ID)
From 2010 to 2014 horizontal drilling activity in the Wolfcamp was focused in the southern Midland Basin, primarily within western Irion, northern Crockett, and southeastern Reagan counties. Well results were extremely variable due to a variety of reasons such as matrix quality, hydrocarbon saturation, faulting, influx of carbonate debris flows, operator, etc, and to this day remain variable. Filtering the well results by operator, vintage, completion style, and target formation helps to explain much of the variation, yet when the above variables were controlled for, large differences in productivity still exist across small distances.
Tracker began this project with approximately 42 square miles (mi2) of 3D seismic data, and during the course of the next five years licensed an additional 88 mi2 of 3D seismic data from offset operators. Tracker worked with APEX Petroleum Engineering (APEX, formerly SIGMA3) to construct a 3D reservoir model that utilized core, wells with full log suites, and ~130 mi2 of prestack time migrated seismic to delineate target zones. While the Wolfcamp is almost entirely hydrocarbon charged, these volumes were used to map a sequence of stacked high-quality landing targets and clearly show the limit of the deep basin sediments to the east onto the basin margin slope. The seismic volumes also shed light on how our offset operators were targeting and drilling their horizontal wells.
While evaluating offset operator wellbore surveys against the reservoir model volumes we noticed large variations in wellbore paths and exposure to high porosity, hydrocarbon charged reservoir rock. These large variations in exposure to the preferred target interval played a large role in the statistical scatter of well results (Figure 1) as well as our model for drilling and completing a more economic well data set.
In early 2017 Tracker began drilling 16 horizontal Wolfcamp wells that were planned using the seismic depth volumes. Well paths were planned to minimize inclination/trajectory changes while avoiding hazards, with the goal of keeping 100% of the lateral in the targeted high-quality zone. Well performance thus far has been excellent when compared to the approximately 615 horizontal wells drilled in the immediate neighborhood. One aspect that has stood out from this analysis is the consistency/similarity in production from the Tracker wells, even though 3 distinct benches were tested. This consistency in results is likely due to the ability to stay in the target zone with minimal inclination changes, large high intensity engineered completions, and detailed flowback procedures which managed drawdown based on bottom hole flowing pressures.
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).
Objectives/Scope: Understanding that capillary forces will act to limit petroleum fluid saturations in water-wet fine-grained rocks, including organic rich source rocks, dates back at least to Hubbert (1953). Likewise, Philippi (1965) noted relationships identifying sorption in/on organic matter as a significant storage mechanism in organic-rich rocks. Contrast these early insights with current unconventional reservoir evaluation, where we observe a disconnect between in situ (core exhumed to surface) measured total water saturations vs. the produced cumulative water volumes from a given stimulated rock volume. Water-free production in gas shales, from gas-wet organic matrix pores, created an early impression that unconventional plays don't produce water. So, in more liquid-rich plays, water cuts were initially under-appreciated: e.g. >80% in the Wolfcamp (stock-tank basis). If measured Sw is so low (core-based calibration), where is the water coming from; or is there an alternative method to more accurately relate in situ to produced water and petroleum production?
Methods/Procedures/Process: Adapting organic sorption models from the 80's, we can split total hydrocarbon volatiles into sorbed and, by difference, non-sorbed (fluid phase) yields. Converting to volumes and adding back dissolved gas using a formation volume factor (FVF) we can estimate the bulk volume fluid phase. This new approach then yields observations regarding remaining water-filled pore volume versus sorbed and non-sorbed hydrocarbon volume explaining the high water cuts in the Permian Basin stratigraphy; and additionally may indicate sweet spots in pore systems in different parts of the rock compared to alternatively derived saturations.
Results/Observations/Conclusions: The final piece of the puzzle comes from basin modeling of petroleum charging in the 90's. Some scientists applied conventional reservoir relative permeability to fine-grained rocks, but new research predicted that progressively finer grained rocks with higher irreducible water should be able to flow oil at progressively higher Sw: at 100nD, both oil and water should flow at Sw > 80%. Lower petroleum phase saturations and adjusted relative permeability curves may better explain observed production behaviors and profoundly alter our view of recovery factor and stimulated rock volume.
Applications/Significance/Novelty: The method offers an alternate and independent method to Dean-Stark-based core / SWC saturation analysis and its pitfalls. Saturation patterns after removal of immobile sorbed oil are different to those derived using the Dean-Stark based method, implying sweet spots / landing zones can be further optimized even in maturing shale plays. Lower oil-in-place – representing only the potentially mobile fluid phase petroleum – means that fracture stimulation has a higher recovery factor than previously thought, with profound effects on the infill volumes / opportunities for future field developments and therefore ultimately for US – and global – oil supply projections.
Interdisciplinary Components: Cross-over technology from organic geochemistry to petrophysics to reservoir engineering.