Brian McPherson

Pore networks in continental and marine mudstones: characteristics and controls on sealing behavior.

Mudstone pore networks are strong modifiers of sedimentary basin fluid dynamics and have a critical role in the distribution of hydrocarbons and containment of injected fluids. Using core samples from continental and marine mudstones, we investigate properties of pore types and networks from a variety of geologic environments, together with estimates of capillary breakthrough pressures by mercury intrusion porosimetry. Analysis and interpretation of quantitative and qualitative three-dimensional (3D) observations, obtained by dual focused ion beam–scanning electron microscopy, suggest seven dominant mudstone pore types distinguished by geometry and connectivity. A dominant planar pore type occurs in all investigated mudstones and generally has high coordination numbers (i.e., number of neighboring connected pores). Connected networks of pores of this type contribute to high mercury capillary pressures due to small pore throats at the junctions of connected pores and likely control most matrix transport in these mudstones. Other pore types are related to authigenic (e.g., replacement or pore-lining precipitation) clay minerals and pyrite nodules; pores in clay packets adjacent to larger, more competent clastic grains; pores in organic phases; and stylolitic and microfracture-related pores. Pores within regions of authigenic clay minerals often form small isolated networks (

CO2 Accounting and Risk Analysis for CO2 Sequestration at Enhanced Oil Recovery Sites.

Using CO2 in enhanced oil recovery (CO2-EOR) is a promising technology for emissions management because CO2-EOR can dramatically reduce sequestration costs in the absence of emissions policies that include incentives for carbon capture and storage. This study develops a multiscale statistical framework to perform CO2 accounting and risk analysis in an EOR environment at the Farnsworth Unit (FWU), Texas. A set of geostatistical-based Monte Carlo simulations of CO2-oil/gas-water flow and transport in the Morrow formation are conducted for global sensitivity and statistical analysis of the major risk metrics: CO2/water injection/production rates, cumulative net CO2 storage, cumulative oil/gas productions, and CO2 breakthrough time. The median and confidence intervals are estimated for quantifying uncertainty ranges of the risk metrics. A response-surface-based economic model has been derived to calculate the CO2-EOR profitability for the FWU site with a current oil price, which suggests that approximately 31% of the 1000 realizations can be profitable. If government carbon-tax credits are available, or the oil price goes up or CO2 capture and operating expenses reduce, more realizations would be profitable. The results from this study provide valuable insights for understanding CO2 storage potential and the corresponding environmental and economic risks of commercial-scale CO2-sequestration in depleted reservoirs.

Evaluation of trapping mechanisms in geologic CO2 sequestration: Case study of SACROC northern platform, a 35-year CO2 injection site

CO2 trapping mechanisms in geologic sequestration are the specific processes that hold CO2 underground in porous formations after it is injected. The main trapping mechanisms of interest include (1) fundamental confinement of mobile CO2 phase under low-permeability caprocks, or stratigraphic trapping, (2) conversion of CO2 to mineral precipitates, or mineral trapping, (3) dissolution in in situ fluid, or solubility trapping, and (4) trapping by surface tension (capillary force) and, correspondingly, remaining in porous media as an immobile CO2 phase, or residual CO2 trapping. The purpose of this work is to evaluate and quantify the competing roles of these different trapping mechanisms, including the relative amounts of storage by each. For the sake of providing a realistic appraisal, we conducted our analyses on a case study site, the SACROC Unit in the Permian basin of western Texas. CO2 has been injected in the subsurface at the SACROC Unit for more than 35 years for the purpose of enhanced oil recovery. Our analysis of the SACROC production and injection history data suggests that about 93 million metric tons of CO2 were injected and about 38 million metric tons were produced from 1972 to 2005. As a result, a simple mass-balance suggests that the SACROC Unit has accumulated approximately 55 million metric tons of CO2. Our study specifically focuses on the northern platform area of the SACROC Unit where about 7 million metric tons of CO2 is stored. In the model describing the SACROC northern platform, porosity distributions were defined from extensive analyses of both 3-D seismic surveys and calibrated well logging data from 368 locations. Permeability distributions were estimated from determined porosity fields using a rock-fabric classification approach. The developed 3-D geocellular model representing the SACROC northern platform consists of over 9.4 million elements that characterize detailed 3-D heterogeneous reservoir geology. To facilitate simulation using conventional personal computers, we upscaled the 9.4 million elements model using a “renormalization” technique to reduce it to 15,470 elements. Analysis of groundwater chemistry from both the oil production formations (Cisco and Canyon Groups) and the formation above the sealing caprock suggests that the Wolfcamp Shale Formation performs well as a caprock at the SACROC Unit. However, results of geochemical mixing models also suggest that a small amount of shallow groundwater may be contaminated by reservoir brine possibly due to: (1) downward recharge of recycled reservoir brine from brine pits at the surface, or (2) upward leakage of CO2-saturated reservoir brine through the Wolfcamp Shale Formation. Using the upscaled 3-D geocellular model with detailed fluid injection/production history data and a vast amount of field data, we developed two separate models to evaluate competing CO2 trapping mechanisms at the SACROC northern platform. The first model simulated CO2 trapping mechanisms in a reservoir saturated with brine only. The second model simulated CO2 trapping mechanisms in a reservoir saturated with both brine and oil. CO2 trapping mechanisms in the brine-only model show distinctive stages accompanying injection and post-injection periods. In the 30-year injection period from 1972 to 2002, the amount of mobile CO2 increased to 5.0 million metric tons without increasing immobile CO2, and the mass of solubility-trapped CO2 sharply rose to 1.7 million metric tons. After CO2 injection ceased, the amount of mobile CO2 dramatically decreased and the amount of immobile CO2 increased. Relatively small amounts of mineral precipitation (less than 0.2 million metric tons of CO2 equivalent) occurred after 200 years. In the brine-plus-oil model, dissolution of CO2 in oil (oil-solubility trapping) and mobile CO2 dominated during the entire simulation period. While supercritical-phase CO2 is mobile near the injection wells due to the high CO2 saturation, it behaves like residually trapped CO2 because of the small density contrast between oil and CO2. In summary, the brine-only model reflected dominance by residual CO2 trapping over the long term, while CO2 in the brine-plus-oil model was dominated by oil-solubility trapping.

Overpressures in the Uinta Basin, Utah: Analysis using a three‐dimensional basin evolution model

High pore fluid pressures, approaching lithostatic, are observed in the deepest sections of the Uinta basin, Utah. Geologic observations and previous modeling studies suggest that the most likely cause of observed overpressures is hydrocarbon generation. We studied Uinta overpressures by developing and applying a three-dimensional, numerical model of the evolution of the basin. The model was developed from a public domain computer code, with addition of a new mesh generator that builds the basin through time, coupling the structural, thermal, and hydrodynamic evolution. Also included in the model are in situ hydrocarbon generation and multiphase migration. The modeling study affirmed oil generation as an overpressure mechanism, but also elucidated the relative roles of multiphase fluid interaction, oil density and viscosity, and sedimentary compaction. An important result is that overpressures by oil generation create conditions for rock fracturing, and associated fracture permeability may regulate or control the propensity to maintain overpressures.

Modeling of Spatiotemporal Thermal Response to CO 2 Injection in Saline Formations: Interpretation for Monitoring

We evaluated the thermal processes with numerical simulation models that include processes of solid NaCl precipitation, buoyancy-driven multiphase SCCO2 migration, and potential non-isothermal effects. Simulation results suggest that these processes—solid NaCl precipitation, buoyancy effects, JT cooling, water vaporization, and exothermic SCCO2 reactions—are strongly coupled and dynamic. In addition, we performed sensitivity studies to determine how geologic (heat capacity, brine concentration, porosity, the magnitude and anisotropy of permeability, and capillary pressure) and operational (injection rate and injected SCCO2 temperature) parameters may affect these induced thermal disturbances. Overall, a fundamental understanding of potential thermal processes investigated through this research will be beneficial in the collection and analysis of temperature signals collectively measured from monitoring wells.

The role of particle packing in modeling rock mechanical behavior using discrete elements

Introduction Both particle packing and particle contact parameters play important roles in determining the mechanical behavior of a discrete particle assembly. One common approach to calibrate discrete element models (DEM) of rock is to hold particle packing constant while contact parameters are changed to match observed macroscopic mechanical behavior. This often leads to non-unique material calibrations. In other words, the mechanical properties of the DEM assembly depend on the packing method. Another problem with this technique is that the parameters that describe contact interactions of particles are not directly observable in the laboratory. An opposite approach is to suggest that since we can actually observe rock texture and packing in rocks, why not mimic this in the model and keep contact parameters constant? The best method probably lies somewhere between these two end-members as suggested by mineralogical observations (i.e. not all grains have the same mechanical properties) and textural observations (i.e. our inability to capture minute details of grain shapes) of rocks (Kranz, 1983). In this context, the purpose of this paper is to gain an understanding of how different particle packing and textures influence the mechanical response of discrete assemblies. One of our hypotheses is that a more physically based calibration of a material may ultimately result in a more unique set of contact parameters. We performed numerical experiments using (1) varying clusters made up of a finite number of particles to represent unique shapes, and (2) using two different assembly generation algorithms to pack them. These issues of the competing roles of particle packing and contact parameters become even more important when modeling coupled processes such as fluid flow and mechanical behavior. This is because of the obvious dependence of fluid flow on the material packing geometry.

Tectonic Influences on Ground Water Quality: Insight from Complementary Methods

A study using multiple techniques provided insight into tectonic influences on ground water systems; the results can help to understand ground water systems in the tectonically active western United States and other parts of the world. Ground water in the San Bernardino Valley (Arizona, United States and Sonora, Mexico) is the main source of water for domestic use, cattle ranching (the primary industry), and the preservation of threatened and endangered species. To improve the understanding of ground water occurrence, movement, and sustainability, an investigation was conducted using a number of complementary methods, including major ion geochemistry, isotope hydrology, analysis of gases dissolved in ground water, aquifer testing, geophysics, and an examination of surface and subsurface geology. By combining information from multiple lines of investigation, a more complete picture of the basin hydrogeology was assembled than would have been possible using fewer methods. The results show that the hydrogeology of the San Bernardino Valley is markedly different than that of its four neighboring basins in the United States. The differences include water quality, chemical evolution, storage, and residence time. The differences result from the locally unique geology of the San Bernardino Valley, which is due to the presence of a magmatically active accommodation zone (a zone separating two regions of normal faults with opposite dips). The geological differences and the resultant hydrological differences between the San Bernardino Valley and its neighboring basins may serve as a model for the distinctive nature of chemical evolution of ground water in other basins with locally distinct tectonic histories.

Thermal analysis of the southern Powder River Basin, Wyoming

Temperature and geologic data from over 3000 oil and gas wells within a 180 km × 30 km area that transect across the southern Powder River Basin in Wyoming, U.S.A., were used to determine the present thermal regime of the basin. Three‐dimensional temperature fields within the transect, based on corrected bottomhole temperatures (BHTs) and other geologic information, were assessed using: (1) A laterally constant temperature gradient model in conjunction with an L1 norm inversion method, and (2) a laterally variable temperature gradient model in conjunction with a stochastic inversion technique. The mean geothermal gradient in the transect is 29°C/km, but important lateral variations in the geothermal gradient exist. The average heat flow for the southern Powder River Basin is 52mW/m2 with systematic variations between 40mW/m2 and 60mW/m2 along the transect. Extremely high local heat flow (values up to 225mW/m2) in the vicinity of the Teapot Dome and the Salt Creek Anticline and low heat flow of 25mW/m2 occ...

Leakage pathway estimation using iTOUGH2 in a multiphase flow system for geologic CO 2 storage

The objective of this study is to apply an inverse analysis using the iTOUGH2 model to estimate the location of a leakage pathway in multiple brine reservoirs when CO2 is injected. If a reservoir exhibits leakage, brine or CO2 is able to migrate into a permeable reservoir overlying the storage reservoir. Fluid pressure anomalies induced by leaks in the overlying reservoir can be distributed differently depending on the leakage locations and rates. Thus, the application of an inverse model utilizes specific pressure anomalies for leakage pathway detection. Prior to applying the inverse analysis, a forward simulation and a sensitivity analysis are conducted. The result of forward simulation demonstrates the interrelation between migrations of brine or CO2 through the leakage pathway and pressure anomalies in the leakage pathway and reservoirs. The sensitivity analysis is performed to evaluate/identify the most influential model inputs on the observed pressure signals and the most appropriate monitoring wells for leakage pathway estimation. The inverse modeling examines the impact of the input parameter’s uncertainties, the number of monitoring wells, observed periods of leakage signal, and noises in the measurements on the leakage pathway estimation through thirteen simulation scenarios. Residual (between the measured pressure and the calculated pressure) analysis illustrates that pressure anomalies in the overlying reservoir induced by leaks are critical information for leakage pathway estimation. The accuracy of the leakage detection using inverse analysis can significantly depend on the number of monitoring wells and the magnitude of the pressure anomalies.

Early results from a laboratory-scale pilot-plant demonstration of enzyme-catalyzed CO2 sequestration with produced waters as cation source

Publisher Summary This chapter develops a system resembling a CO2 scrubber that can provide a route to safe, long-term sequestration of CO2 from, for example, fossil-fuel-burning power plants. It has been estimated that an amount of carbon equivalent to 150,000 × 1012 tonnes of CO2 is naturally sequestered in the form of carbonate minerals, such as calcite, aragonite, dolomite, and dolomitic limestone, which thus constitute the earths largest CO2 reservoir. Mineralization is attractive as a possible route to carbon sequestration because it offers the potential for safe storage of very large quantities of CO2 over very long time periods, as demonstrated by the geological record. This would, of course, minimize risks and monitoring requirements, and facilitate licensing. Produced waters offer a particularly attractive because of the potential to improve cost effectiveness for sequestration while also benefiting the oil and gas industry. In active production areas such as the Permian Basin, substantial amounts of brine are already being produced, transported, and re-injected. Some of these produced waters are used in water flooding for secondary production, but most constitute a waste product requiring disposal.