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A key feature of unconventional shale reservoirs is low permeability. On average, only 10% of original oil in place and 25% of original gas in place is produced from these reservoirs. Understanding the mechanisms behind fracture conductivity past the first couple of years of shale production is still an ongoing research topic, as most such reservoirs report fast and massive production declines. Hydraulic fracturing is indispensable for stimulating low-permeability rocks for economical oil and gas production from unconventional reservoir rocks such as shales. In contrast, for subsurface sequestration and storage of fluids including supercritical CO2 (for carbon capture, utilization, and storage) and hydrogen gas, inadvertent creation of fractures can lead to breaching of shale caprock. The Caney Shale in southern Oklahoma is being evaluated as both a potential hydrocarbon-producing reservoir and a caprock for fluid sequestration. The Caney Shale is a Mississippian-age, organic-rich mudrock with intermittent calcareous laminae, that produces. But currently there is limited data reported regarding productivity of horizontally drilled wellbores. While many scholars have investigated fracture conductivity in shale reservoirs, the mechanisms of proppant embedment in relation to lithology are still under investigation. This study implemented a multi-scale approach towards investigating proppant embedment and fracture conductivity, from nano-scale instrumented micro/nano-indentation to millimeter (mm) scale, mono-layer propped fracture flow at reservoir temperature and pressure, and American Petroleum Institute (API)-RP19D conductivity tests using inch/cm-scale shale platens. At each scale, various material characterization tools were utilized, including Focused Ion Beam-Scanning Electron Microscopy (FIB-SEM), Energy Dispersive Spectroscopy (EDS), Raman spectroscopy, Laser profilometry, Computed X-ray Microscopy and X-ray Diffraction (XRD). The outcomes of the micro-indentation revealed variations in mechanical properties attributed to changing mineral composition and microstructures. Outcomes from API fracture conductivity testing and flow-through testing using a monolayer of proppant demonstrated: (1) a 50% impact on proppant embedment compared to ductile samples, (2) a significant decline in fracture conductivity with increasing stress and temperatures, and (3) conductivity that was also influenced by organic and inorganic content as well as internal sample architecture. Mineralogically, ductile samples contain about 25% more clay minerals compared to brittle regions. Heterogeneity in mineral composition causes the Caney Shale to show different responses at reservoir temperature and pressure, particularly in relation to creep and proppant embedment. Geomechanical and fluid-flow modeling have been conducted at several scales to help interpret laboratory results and apply findings to field-scale operation. The outcomes from this integration should aid geological and engineering predictions for the hydrocarbon production and caprock integrity of the Caney Shale.

To reduce the geothermal exploration risk, a feasibility study is performed for a deep direct-use (DDU) system proposed at the West Virginia University (WVU) Morgantown campus. This study applies numerical simulations to investigate reservoir impedance and thermal production. Because of the great depth of the geothermal reservoir, few data are available to characterize reservoir features and properties. As a result, the study focuses on the following three aspects: 1. model choice for predicting reservoir impedance and thermal breakthrough: after investigating three potential models (one single permeability model and two dual permeability models) for flow through fractured rock, it is decided only the single permeability model is needed; 2. well placement (horizontal vs. vertical) options: horizontal well placement seems to be more robust to heterogeneity and the impedance is more acceptable; 3. Prediction uncertainty: the most influential parameters are identified using a First-Order-Second-Moment uncertainty propagation analysis, and the uncertain range of the model predictions is estimated by performing a Monte Carlo simulation. Heterogeneity has a large impact on the prediction, therefore, heterogeneity is included in the predictive model and uncertainty analysis. The numerical model results and uncertainty analysis will be used for further economic studies.

Uncertainty in the long-term fate of CO2 injected for geologic carbon sequestration (GCS) is a significant barrier to the adoption of GCS as a greenhouse-gas emission-mitigation for industry and regulatory agencies alike. We present a modeling study that demonstrates that the uncertainty in forecasts of GCS site performance decreases over time as monitoring data are used to update operational models. We consider a case study of GCS in a depleted natural gas reservoir, with CO2 injection occurring over 20 years, with a 50-year post-injection site care period. We constructed a detailed model to generate the actual model output, which is considered synthetic observation data. A series of simpler operational models based on limited data and assumptions about how an operator would model such a site are then run and compared against actual model output at specific monitoring points after one year, two years, etc. The operational model is updated and improved using the synthetic observation data from the actual model at the same time intervals. Model parameter values and model features needed to be updated over time to improve matches to the actual model. These kinds of model adjustments would be a normal part of reservoir engineering and site management at GCS sites. Uncertainty in two key measures related to site performance decreases with time: extent of the CO2 plume up-dip migration, and radial extent of the pressure pulse. This conclusion should help allay the concerns of industry and regulators about uncertainty in long-term fate of CO2 at GCS sites.

The quantification of recharge and trans-valley underflow is needed in arid regions to estimate the impacts of new water withdrawals on the water table. However, for mountainous desert areas, such estimates are highly challenging, due to data scarcity, heterogeneous soils, and long residence times. Conventional assessment employs isolated groundwater models configured with simplified uniform estimates of recharge. Here, we employed a data-constrained surface-subsurface process model to provide an ensemble of spatially distributed recharge and underflow estimates using perturbed parameters. Then, the Model-Independent Parameter Estimation and Uncertainty Quantification (PEST) package was used to calibrate the aquifer hydraulic conductivity field in MODFLOW for this ensemble and reject implausible recharge values. This novel dual-model approach, broadly applicable to mountainous arid regions, was designed to maximally exploit available data sources. It can assimilate groundwater head observations, reject unrealistic parameters, and narrow the range of estimated drawdowns due to pumping. We applied this approach to the Chuckwalla basin in California, USA to determine natural recharge. Simulated recharge concentrates along alluvial fans at the mountain fronts and ephemeral washes where run-off water infiltrates. If an evenly distributed recharge was employed as in conventional studies, it would result in regional biases in estimated drawdown and larger uncertainty bounds. We also note that the speed of groundwater recovery does not guarantee sustainability: heavy pumping induces large hydraulic gradients that initially recover quickly when pumping is halted, but the system may not ultimately recover to pre-pumping levels.

Understanding the changes in the saturation within a reservoir undergoing enhanced oil recovery (EOR) is crucial to optimizing production. We debut a novel, multiphase fluid flow modelling code, TOGA, to assist in modeling gas, oil, and water phases within the reservoir, and combine its output with time-lapse Depth to Surface Resistivity data in a case study involving an EOR reservoir. The results show the potential for combining the two methods to improve our understanding of reservoir saturation over an extended period of time.

With the goal of detecting and characterizing faults and fractures in enhanced geothermal systems (EGS), a new technology involving CO2 push-pull testing, active-source geophysical imaging, and well logging has recently been proposed. This technique takes advantage of (1) the contrasting properties of supercritical CO2 and water which cause CO2 to appear distinct from surrounding brine in seismic and other geophysical logging approaches, (2) the non-wetting nature of CO2 which keeps it localized to the faults and fractures to create contrast potentially sufficient for active seismic and well-logging approaches to image faults and fracture zones at EGS sites. In this study, we evaluate the feasibility of using pressure transient monitoring during CO2 push-pull tests to complement active seismic and wireline well logging for EGS characterization. For this purpose, we developed a 2D model of a prototypical geothermal site (Desert Peak, NV) that includes a single fault. The fault zone consists of a slip plane, fault gouge, and damage zone, and is bounded by the surrounding matrix of the country rock. Through numerical simulation using iTOUGH2, we found that the pressure transient at the monitoring wells in the fault gouge shows unique traits due to the multiphase flow conditions developed by CO2 injection, and varies sensitively on the arrival of the CO2 plume and the degree of CO2 saturation. A sensitivity analysis shows the pressure transient is most sensitive to the fault gouge permeability, but also depends on multiphase flow parameters and the boundary conditions of the fault. An inversion study reveals that the fault gouge permeability can be best estimated with the pressure transient data, whereas additional CO2 saturation data do not improve the accuracy of the inversion significantly.

Characterizing the faults and fractures that provide flow pathways for efficient geothermal energy production is critical for design of sustainable geothermal energy production. Both natural faults and stimulated fractures in enhanced geothermal systems (EGS) are difficult to image and map by seismic methods because hot brine filling the fractures and faults does not create a strong seismic property contrast relative to surrounding rock. We investigate here the technical feasibility of using supercritical CO2 (scCO2) injection into faults in a single-well push-pull scenario to characterize the hydraulic properties of the fault zone by emplacing scCO2 that can serve as a contrast fluid for seismic monitoring. We develop a conceptual and numerical reservoir model of two intersecting faults based on the Dixie Valley geothermal system in Nevada, USA. The 2D conceptual model consists of a system with a main fault and an intersecting conjugate fault. The corresponding numerical model is discretized using irregular grid blocks with fine discretization around the slip plane, gouge, and damage zones. We perform forward modeling along with sensitivity and data-worth analyses of scCO2 push-pull to investigate the CO2 distribution in the fault gouge during 30 days of push (injection) and 30 days of pull (production). Formal sensitivity analysis is conducted to determine the most controlling unknown parameters in the fault zones. Using the selected set of unknown parameters and output responses, we perform data-worth analysis to reveal the most valuable output response to be measured for the best prediction of CO2 distribution in the fault zones and its uncertainty. From the results of data-worth analysis, we determine the optimal properties to target in monitoring, their locations, and the minimum observation time. Our results provide information on the optimal design of scCO2 push-pull testing in a conjugate fault system modeled after Dixie Valley that can be used to enhance monitoring by active seismic and well-logging methods to better characterize the transmissive fault(s).

The capability to conduct a rapid, near real-time model-based analysis of production data from tight/shale (TS) gas fields is important in determining fracture and matrix properties. Model-based analysis of production can range from simple analytical solutions to complex numerical models. The objective of this study is to develop a simple, Excel-based tool for the analysis of the complex problem of gas production from a fractured TS gas reservoir that is based on a robust model that is faithful to the underlying physics and can provide rapid estimates of the important system parameters. The scientifically robust model used as the basis for this tool is a significant modification and expansion of the bimodal production decline curve of Silin and Kneafsey (2012). The production period is divided into two regimes: an early-time regime before the extent of the stimulated reservoir volume (SRV) is felt, where an analytical similarity solution for gas production rate is obtained, and a late-time regime where the rate can be approximated with an exponential decline or more accurately represented with a numerical integration. Our basic model follows Silin and Kneafsey (2012) and produces the widely observed -½ slope on a log-log plot of early-time production decline curves, while our expanded model generalizes this slope to –n, where 0 < n < 1, to represent non-ideal flow geometries. The expanded model was programmed into an Excel spreadsheet to develop an interactive, user-friendly application for curve matching of well production data to the bimodal curve, from which matrix and fracture properties can be extracted. This tool allows significant insight into the model parameters that control the reservoir behavior and production: the geometry of the hydraulically-induced fracture network, its flow and transport properties, and the optimal operational parameters. This information enables informed choices about future operations, and is valuable in several different ways: (a) to estimate reserves and to predict future production, including expected ultimate recovery and the useful lifetime of the stage or the well; (b) if curve-matching is unsuccessful, to indicate the inadequacy of the mathematical model and the need for more complex numerical model to analyze the system; (c) to verify/validate numerical models, and to identify anomalous behavior or measurement errors in the data. The present approach can be adapted to gas-flow problems in dual-permeability media (hydraulically or naturally fractured) or highly heterogeneous sedimentary rock, as well as to retrograde condensation.

CO2 has been proposed as a working fluid for geothermal energy production because of its ability to establish a self-sustaining CO2 thermosiphon, taking advantage of the strong temperature dependence of CO2 density. To test the concept of CO2 heat extraction, in January 2015 a CO2 thermosiphon was operated at the SECARB Cranfield Site, Cranfield, Mississippi, where a brine-saturated sand at a depth of 3.2 km has been under near continuous CO2 flood since December 2009 as part of a U.S. Department of Energy demonstration of CO2 sequestration, resulting in a partially saturated reservoir surrounding a well pair. The lateral distance between the producer and injector was 112 m at reservoir depth, a distance considered pre-commercial in scale, but great enough that thermal breakthrough was still not significant after several years of injection. Instead of producing power with a turbine, heat was extracted heat from recirculated fluid using a heat exchanger and portable chiller. The well field and surface equipment were instrumented to compare field observations with predicted responses from numerical models. Thermosiphon flow could be initiated by venting, but thereafter flow rate steadily declined, indicating that the thermosiphon was not sustainable. To model the system, the capability of T2Well, a fully coupled wellbore/reservoir numerical simulator, was expanded to enable simulation of the entire loop of fluid circulation in the fully-coupled system consisting of the injection/production wells, the reservoir, and the surface devices (heat exchanger, flow-rate regulator etc.). Combined with the newly developed TOUGH2 equation of state module called EOS7CMA, the enhanced T2Well was used prior to the field experiment to simulate the circulation of a CO2-H2O-CH4 mixture in a model geothermal system patterned after the Cranfield demonstration test. The model predicted that a sustainable thermosiphon could be achieved. After the field thermosiphon did not achieve the pre-test prediction of flow rates and thermosiphon sustainability, the numerical model was modified to improve realism and calibrate certain processes; it was then able to reproduce the major phenomena observed in the field. In a series of sensitivity studies, many factors were found that could potentially contribute to the failing of a sustainable thermosiphon. These factors could be categorized as two types: factors that increase the resistance to flow and factors that increase heat loss of the working fluid. The lessons learned can be applied to both future modeling and to achieving CO2-based geothermal reservoir exploitation.

The grid generation capability built into the numerical simulator TOUGH for multi-phase fluid and heat flow through geologic media can create one-column grids with linear or radial geometry, corresponding to one-dimensional or two-dimensional radial flow, respectively. The integral-finite-difference-method that TOUGH employs for spatial discretization makes it very simple to generalize the grid-generation algorithm from integer to non-integer (fractal) flow dimension. Here the grid-generation algorithm is generalized to create one-column grids with fractal flow dimension ranging from less than 1 to 3. The fractal grid generation method is verified by comparing numerical simulation results to an analytical solution for a generalized Theis solution for integer and non-integer flow dimensions between 0.4 and 3. It is then applied to examine gas production decline curves from hydraulically fractured shale that is modeled as a fractal-dimensioned fracture network with flow dimensions between 0.25 and 3. Grids with fractal flow dimension are useful for representing flow through fracture networks or highly heterogeneous geologic media with fractal geometry, and may be particularly useful for inverse methods.

We have improved ECO2N, the TOUGH2 fluid property module of the CO2-H2O-NaCl system. The major enhancements include: (i) the upper temperature limit is increased from 110 to about 300°C; (ii) the thermophysical properties of the CO2-rich phase are more accurately calculated as a non-ideal mixture of CO2 and H2O; (iii) the approach to calculate the specific enthalpy of dissolved CO2 has been improved to make the code more robust in modeling phase transitions under non-isothermal conditions; and (iv) more sophisticated models for effective heat conductivity of formations saturated with supercritical CO2 have been provided. The new module includes a comprehensive description of the thermodynamic and thermophysical properties of H2ONaClCO2 mixtures, that reproduces fluid properties largely within experimental error for the temperature, pressure and salinity conditions 10°C < T < 300°C, P < 600 bar, and salinity up to halite saturation. This includes density, viscosity, and specific enthalpy of fluid phases as functions of temperature, pressure, and composition, as well as partitioning of mass components H2O, NaCl and CO2 among the different phases. ECO2N with the TOUGH2 reservoir simulator can be applied to a wide range of problems in geologic sequestration of CO2 in saline aquifers, and in enhanced geothermal reservoirs. ECO2N can describe both sub- and supercritical states of CO2, but applications that involve subcritical conditions are limited to systems in which there is no change of phase between liquid and gaseous CO2, and in which no mixtures of liquid and gaseous CO2 occur. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd.

Flowing fluid electrical conductivity (FFEC) logging is a hydrogeologic testing method that is usually conducted in an existing borehole. However, for the 2,500-m deep COSC-1 borehole, drilled at Åre, central Sweden, it was done within the drilling period during a scheduled 1-day break, thus having a negligible impact on the drilling schedule, yet providing important information on depths of hydraulically conductive zones and their transmissivities and salinities. This paper presents a reanalysis of this set of data together with a new FFEC logging data set obtained soon after drilling was completed, also over a period of 1 day, but with a different pumping rate and water-level drawdown. Their joint analysis not only results in better estimates of transmissivity and salinity in the conducting fractures intercepted by the borehole, but also yields the hydraulic head values of these fractures, an important piece of information for the understanding of hydraulic structure of the subsurface. Two additional FFEC logging tests were done about 1 year later, and are used to confirm and refine this analysis. Results show that from 250 to 2,000 m depths, there are seven distinct hydraulically conductive zones with different hydraulic heads and low transmissivity values. For the final test, conducted with a much smaller water-level drawdown, inflow ceased from some of the conductive zones, confirming that their hydraulic heads are below the hydraulic head measured in the wellbore under non-pumped conditions. The challenges accompanying 1-day FFEC logging are summarized, along with lessons learned in addressing them.

Shallow, heavy oil diatomite reservoirs produced using cyclic steaming are often associated with significant subsidence. In cases where the pore pressure is not allowed to deplete noticeably, observed subsidence suggests a mechanism other than pressure decline is responsible. We perform coupled flow and geomechanics modeling to determine whether thermally induced compaction of the reservoir rock could play an important role in subsidence. First, we model laboratory-scale tests on diatomite samples subjected to mechanical and thermal loads. During these tests, substantial non-recoverable thermal compaction was measured. Using the modified Cam-clay model as a basis, thermally induced compaction is implemented by reducing the size of the yield surface as a function of temperature. This leads to a satisfactory modeling of the test results. Second, this new approach is used to model a symmetric pattern of wells in a generic heavy oil diatomite field produced using cyclic steaming. Results from simulations that consider or neglect thermally induced diatomite compaction show that thermal effects can potentially induce significant inelastic pore volume reduction and substantial subsidence.

Daytime Net Ecosystem CO2 uptake (NEE) in an Amazon forest has been shown to increase significantly during smoky periods associated with biomass burning. We investigated whether the increase in CO2 uptake is caused by increased irradiance in the lower canopy, which results from increased above-canopy diffuse light, or by decreased canopy temperature, which results from decreased above-canopy net radiation. We used Sun photometers measuring aerosol optical depth to find nonsmoky (Aerosol Optical Depth (AOT) < 0.35), smoky (AOT > 0.5) and very smoky (AOT > 0.7) periods for the Tapajos region in the Amazon. Using a network of subcanopy photosynthetic photon flux density (PPFD) sensors, we detected a ∼4 μmol m−2 s−1 increase in subcanopy diffuse light during smoky periods relative to nonsmoky periods. Using a pyrgeometer to measure upwelling longwave radiation and, hence, canopy surface temperature, we found a ∼0.5°C cooling relative to air temperature during smoky periods. We modeled subcanopy irradiance based on the subcanopy PPFD sensors and combined this with subcanopy leaf photosynthesis measurements to determine how the increased lower canopy light affected NEE. We used the relationship between temperature and NEE measured by eddy covariance to determine the effect of decreased canopy temperature on canopy CO2 uptake. We found that the increase in CO2 uptake at high aerosol optical depths is primarily a result of increased shaded light in the subcanopy (accounting for ∼80%) and to a lesser extent the effect of decreased canopy temperature (accounting for ∼20%).

The density and viscosity of supercritical CO2 are sensitive to pressure and temperature (PT) while the viscosity of brine is sensitive primarily to temperature. Oil field PT data in the vicinity of WESTCARB's Phase III injection pilot test site in the southern San Joaquin Valley, California, show a range of PT values, indicating either PT uncertainty or variability. Numerical simulation results across the range of likely PT indicate brine viscosity variation causes virtually no difference in plume evolution and final size, but CO2 density variation causes a large difference. Relative ultimate plume size is almost directly proportional to the relative difference in brine and CO2 density (buoyancy flow). The majority of the difference in plume size occurs during and shortly after the cessation of injection. © 2009 Lawrence Berkeley National Laboratory.

The vadose zone can be characterized as a complex subsurface system in which intricate physical and biogeochemical processes occur in response to a variety of natural forcings and human activities. This makes it difficult to describe, understand, and predict the behavior of this specific subsurface system. The TOUGH nonisothermal multiphase flow simulators are well-suited to perform advanced vadose zone studies. The conceptual models underlying the TOUGH simulators are capable of representing features specific to the vadose zone, and of addressing a variety of coupled phenomena. Moreover, the simulators are integrated into software tools that enable advanced data analysis, optimization, and system-level modeling. We discuss fundamental and computational challenges in simulating vadose zone processes, review recent advances in modeling such systems, and demonstrate some capabilities of the TOUGH suite of codes using illustrative examples.

The flowing fluid electric conductivity (FFEC) logging method is an efficient way to provide information on the depths, salinities, and transmissivities of individual conductive features intercepted by a borehole, without the use of specialized probes. Using it in a multiple-flow-rate mode allows, in addition, an estimate of the inherent "far-field" pressure heads in each of the conductive features. The multi-rate method was successfully applied to a 500-m borehole in a granitic formation and reported recently. The present paper presents the application of the method to two zones within a 1000-m borehole in sedimentary rock, which produced, for each zone, three sets of logs at different pumping rates, each set measured over a period of about one day. The data sets involve a number of complications, such as variable well diameter, free water table decline in the well, and effects of drilling mud. To analyze data from this borehole, we apply various techniques that have been developed for analyzing FFEC logs: direct-fitting, mass-integral, and the multi-rate method mentioned above. In spite of complications associated with the tests, analysis of the data is able to identify 44 hydraulically conducting fractures distributed over the depth interval 150-775 meters below ground surface. The salinities (in FEC), and transmissivities and pressure heads (in dimensionless form) of these 44 features are obtained and found to vary significantly among one another. These results are compared with data from eight packer tests with packer intervals of 10-80 m, which were conducted in this borehole over the same depth interval. They are found to be consistent with these independent packer-test data, thus demonstrating the robustness of the FFEC logging method under non-ideal conditions.

LBNL's GEOSEQ project is a key participant in the Frio II brine pilot studying geologic sequestration of CO2. During During the injection phase of the Frio-II brine pilot, LBNL collected multiple data sets including seismic monitoring, hydrologic monitoring and geochemical sampling. These data sets are summarized in this report including all CASSM (continuous active source seismic monitoring) travel time data, injection pressure and flow rate data and gaseous sampling and tracer data. Additional results from aqueous chemistry analysis performed by the U. S. Geological Survey (USGS) are summarized. Post injection modification of the flow model for Frio II is shown. Thesemodifications are intended to facilitate integration with the monitoring data and incorporation of model heterogeneity. Current activities of LBNL's GEOSEQ project related to the Frio II test are shown, including development of a new petrophysical model for improved interpretation of seismic monitoring data and integration of this data with flow modeling.