Steven L. Bryant

Implications of Coupling Fractional Flow and Geochemistry for CO2 Injection in Aquifers

The geochemical changes caused by CO2 injection into aquifers include acidification and carbonation of the native brine and potential mineral dissolution and precipitation reactions driven by the aqueous composition changes. The latter are important for evaluating the potential CO2 storage capacity in the form of minerals and can also influence the performance of the injection well. The theories of geochemical flows and of fractional flow provide useful insight into several aspects of CO2 sequestration. This paper gives the mathematical formalism of combined geochemical and multi-phase flow. If local equilibrium applies, the theory leads to graphical solution, from which it is easy to see when and under what conditions mineralization will occur during the injection. The theory also illustrates the influence of post-injection flow on mode of CO2 trapping (hydrodynamic, solubility, mineral, residual saturation). We also show that co-injection of water significantly alters the mode of trapping. Introduction Carbon dioxide sequestration was first discussed in the late 1970s. However, serious research and development in CO2 sequestration only began in the early 1990s. The technical literature28 about CO2 disposal in aquifers includes feasibility studies in The Netherlands and in the Alberta Basin, Canada. A field test is being performed in the North Sea in the Sleipner Vest project, which is the first CO2 sequestration project in a brine-bearing formation. Sequestering CO2 in geologic formations offers numerous advantages, including: (1) The experience of the oil industry can directly provide the technology to enable the commercialization of this approach. (2) Several collateral economic benefits are possible, for example, enhancing oil and gas recovery while storing CO2. (3) Suitable geologic formations, including oil, gas, brine, and coal formations are relatively easy to find. (4) The regulatory infrastructure associated with the injection into oil and gas formations and deep aquifers is well established. (5) Geologic analogs such as natural CO2 reservoirs prove that geologic structures can sequester CO2 for a very long time. (6) Public acceptance for geologic sequestration should grow as technological advances lead to innovative methods for creating permanent mineral sinks for CO2. Carbon dioxide can be sequestered in geologic formations by three principal mechanisms. (1) CO2 can be trapped as a gaseous phase or supercritical fluid under a low-permeability caprock, similar to what occurs in natural gas reservoirs (hydrodynamic trapping). (2) Dissolution into an aqueous phase (solubility trapping). (3) CO2 can react with the minerals and the organic matter in geologic formations to become a part of the solid (mineral trapping). Formation of carbonate minerals such as calcite or siderite and the adsorption onto coal are other examples of the mineral trapping. Mineral trapping will create stable repositories of CO2 that decrease mobile hazards such as leakage to the surface. An additional form of storage -as a residual gas saturation -is also studied in this and a companion paper. Here CO2 remains as a gaseous phase, such as hydrodynamic trapping, but it is immobile because the gas is trapped by capillary forces. In this study, the immobile gas trapping is called the residual saturation trapping. Siliciclastic aquifers should have greater potential for the mineral trapping of CO2 compared to carbonate aquifers. Depending on whether the basic aluminosilicate minerals, such as feldspars, zeolites, illites, chlorites and smectites, contain an alkali or alkaline earth cation, two types of mineral trapping can be considered. Na/K-bearing minerals result in the development of bicarbonate brines. Fe/Ca/Mg-bearing minerals result in the precipitation of siderite, calcite or

Numerical Simulation of the Storage of Pure CO2 and CO2-H2S Gas Mixtures in Deep Saline Aquifers

We have studied strategies for maximizing several phenomena beneficial to large-scale subsurface storage of waste gases such as CO2 and H2S. Numerical simulations using a compositional reservoir simulator were carried out for 10,000 years to understand the flow and long-term storage potential of pure CO2 and CO2-H2S mixtures in deep saline aquifers. Hysteresis in the relative permeability curve results in substantial volumes of gas trapping. Aquifer characteristics such as heterogeneity, dip angle and vertical to horizontal permeability ratio were varied to determine their effect on storage potential and injectivity of a CO2-H2S gas mixture. The opportunity for escape of the gases from the aquifer can be minimized by careful design of injection strategies. One such strategy is to use horizontal wells low in the formation so that all of the injected gases are trapped, dissolved or precipitated before they reach geological seals and/or faults. This allows significantly larger volumes of waste gases to be stored in a given aquifer. Preferential solubility of the H2S in brine reduces the distance H2S travels relative to CO2. Simulations with local grid refinement show that fingering due to buoyancy is mitigated by natural heterogeneity in the aquifer petrophysical properties. Thus the amount of gas trapping observed in coarse-grid simulations is likely to be a reasonable estimate of what can be obtained in the field. Three-dimensional simulations of coupled flow and reactive transport showed that the amount of CO2 sequestered as minerals was small relative to gas trapping and dissolution into brine. However, the mineralization further reduces the already small amount of mobile gas over long periods of time.

Simulating CO2 Storage in Deep Saline Aquifers

This chapter presents the results of compositional reservoir simulation of a prototypical CO 2 storage project in a deep saline aquifer. The objective of the investigation was to better understand and quantify estimates of the most important CO 2 storage mechanisms under realistic physical conditions. Simulations of a few decades of CO 2 injection followed by 10 3 -10 5 years of natural gradient flow were done. The impact of several parameters was reviewed, including average permeability, the ratio of vertical to horizontal permeability, residual gas saturation, salinity, temperature, aquifer dip angle, permeability heterogeneity and mineralization. The storage of CO 2 in residual gas emerges as a potentially very significant issue meriting further study. Under some circumstances this form of immobile storage can be larger than storage in brine and minerals.

Reservoir Simulation of CO2 Storage in Deep Saline Aquifers

We present the results of compositional reservoir simulation of a prototypical CO2 sequestration project in a deep saline aquifer. The objective was to better understand and quantify estimates of the most important CO2 storage mechanisms under realistic physical conditions. Simulations of a few decades of CO2 injection followed by 10 to 10 years of natural gradient flow were done. The impact of several parameters was studied, including average permeability, the ratio of vertical to horizontal permeability, residual gas saturation, salinity, temperature, aquifer dip angle, permeability heterogeneity and mineralization. The storage of CO2 in residual gas emerges as a potentially very significant issue meriting further study. Under some circumstances this form of immobile storage can be larger than storage in brine and minerals.

Modeling Leakage Through Faults of CO2 Stored in an Aquifer

For secure storage of CO2 within geologic formations, the integrity of caps – overlying strata that are impervious to CO2 – is an important factor. Geologic structures, notably faults and the damage zones surrounding them may provide a conduit for CO2 to escape through a cap. If the fault encounters shallower permeable formations, the CO2 rising along the fault can enter them. This lateral migration would attenuate the rate at which CO2 enters sensitive formations such as aquifers used for drinking water. Thus, CO2 leakage along faults will have three behaviors: upward migration from the storage formation along a fault, lateral movement from the fault into permeable layers, and a continued but attenuated CO2 flux along the fault above the layers. Here we develop a quasi-1D single-phase flow model for these three behaviors. The model is highly simplified and intended to be suitable for inclusion in a certification framework for geologic storage projects. The model accounts for flow from the fault into a permeable formation using a leakoff coefficient. The coefficient can vary spatially and depends on the geometry and petrophysical properties of the formation. We apply a commercial simulator to verify the quasi-1D model. A series of examples illustrates the controlling mechanisms for leakage rate from the reservoir and its attenuation by flux into shallower layers. Nonlinearities arise even in this simple model. For example, leakage flux and the degree of attenuation vary nonlinearly with the permeability of the fault and the permeability of the shallower layer(s) intersected by the fault. Layers nearest the CO2 storage formation produce the most attenuation. But the percentage of CO2 entering overlying formations from the fault varies linearly with the ratio of fault permeability to leakoff coefficient. A simple estimate of the leak-off coefficient compares favorably with 2D, full-physics simulations. If the permeable layer is dipping, CO2 enters it asymmetrically and estimating the leakoff coefficient is less straightforward. The difference arises because of preferential flow within the layer (CO2 in the upper part, water below). Introduction If society elects to reduce anthropogenic emissions of CO2, geologic storage will be one of the key technologies for achieving this goal. In the standard approach to storage, CO2 is captured from fixed sources such as coal-fired power plants, compressed and injected at supercritical conditions into a suitable target formation. For typical geothermal gradients, suitable formations are found at depths of 800 m (2600 ft) or more, as their temperatures and pressures will be above the critical point of CO2. Trapping the injected CO2 involves one or more mechanisms (Bachu et al. 1994; IPCC 2006): (1) permeability trapping by an impervious confining layer or cap rock; (2) solubility trapping by CO2 dissolution into the aqueous phase in the pore space; (3) mineralogic trapping by chemical reaction of cations with dissolved CO2 to precipitate carbonate minerals; (4) residual phase trapping as the nonwetting CO2 phase becomes disconnected in pores or small clusters of pores; (5) stratigraphic trapping below a formation whose capillary entry pressure is greater than the capillary pressure of the CO2 phase. An intact confining layer is necessary for several trapping mechanisms. However, sedimentary basins often contain geological discontinuities which are potential pathways for leakage through the confining layer. Faults are one such discontinuity and are prevalent in many regions where CO2 storage is likely to be implemented. Wells are a man-made discontinuity, likewise prevalent in likely storage regions. We do not treat them here, but the conceptual model for faults provides a foundation for assessing leakage along wells (Huerta et al. 2008). It is therefore important to examine the consequences if injected CO2 encounters a fault. Figure 1 illustrates the situation of interest. A conductive fault can be a major pathway for the CO2 plume due to its large transfer capacity. However CO2 leaking from the main target formation does not necessarily reach the Earth’s surface. It may not even reach shallower formations of economic interest (mines, hydrocarbon reservoirs, aquifers that serve as underground sources of drinking water (USDW)). Instead, the rising CO2 can be secondarily trapped by shallow subsurface structures, dissolution and residual phase creation (Lindeberg 1997). It can also migrate into permeable formations encountered by the conductive fault. On one hand, this migration attenuates the upward flux. On the other, it spreads the influence of the CO2 across a wider area. The near-surface zone can also attenuate CO2 leaks and decrease CO2 concentration reaching the surface. The attenuation rate is sensitive to the subsurface properties (Oldenburg and Unger 2003). Thus, the effect of a conductive fault on net CO2 storage needs to be analyzed based on the geometric and petrophysical properties of the formation, of the fault and of the overlying permeable layer, and on the boundary conditions (pressure in the storage formation and in the overlying layers). The physics of a CO2 plume rising long vertical distances through the Earth’s crust can be complex (Pruess 2003). Here we present a highly simplified model, motivated by two considerations. One is geological: in many sedimentary basins, a fault is unlikely to be conductive continuously from depth to the shallow subsurface. Leakage to surface or to USDW will involve a sequence of upward (along a fault) and lateral (within a permeable layer) migrations. Thus we will consider moderate conduit lengths of 1000 meters or less. The other consideration is practical: for CO2 storage to be implemented broadly and rapidly enough to mitigate anthropogenic emissions, thousands of storage projects will be needed. Each will have to be permitted by regulators in a streamlined yet robust and transparent way. Unfortunately the physical properties of most storage formations – deep saline aquifers – will be poorly constrained prior to injection. In light of this uncertainty, simple models that allow adequate physics-based risk assessment will be valuable tools for operators, regulators and policymakers. The model presented here was developed to be applicable within the Certification Framework (CF) for geologic storage (Oldenburg and Bryant 2007, Oldenburg et al. 2008). The purpose of the CF is to provide a framework for project proponents, regulators, and the public to analyze the risks of geologic CO2 storage in a simple and transparent way. The risk analysis would be performed to certify the startup and decommissioning of sites for geologic CO2 storage. The CF currently emphasizes risks associated with subsurface processes and excludes compression, transportation, and injection-well leakage risk. The CF is designed to be simple by (1) using proxy concentrations or fluxes, rather than complicated exposure functions, for quantifying impact; (2) using a catalog of pre-computed CO2 injection results (Kumar 2008), and (3) using a simple framework for calculating leakage risk. For transparency, the CF endeavors to be clear and precise in terminology in order to communicate to the full spectrum of stakeholders. One concept of the CF is that leakage occurs along conduits from the storage volume to “compartments” such as hydrocarbon reservoirs or USDW. The risk associated with leakage is the product of the probability of leakage and the impact of that leakage. The flux of CO2 contributes to impact. Thus the goal of the faultleakage model is to estimate flux at an “outlet” of a conductive fault, once CO2 has arrived at the “inlet”. The overarching criteria of the CF and the models within it are simplicity, transparency and acceptability. Here we emphasize the requirement of simplicity. The subsurface data available as input to any numerical model in the CF will always be limited. This limitation is especially troublesome in the case of injection into saline aquifers. Saline aquifers provide large storage capacity but are not well characterized due to the small number of existing wells which could provide geologic information about that particular region of the subsurface. The flow properties of faults are even more uncertain, at least before injection begins. In principle the required properties could be obtained from appropriate measurement campaigns. In practice, measurement will increase the cost of storage, and cost minimization will be a high priority for any greenhouse gas mitigation strategy. Moreover, the most reliable measurements would come from wells drilled into the formation or through the fault. These wells would themselves be potential pathways for leakage. The philosophy of the fault-leakage model is thus to identify the key physical phenomena controlling leakage flux. The sensitivity of the flux to physical parameters provides insight as to which aquifer properties should be measured when designing or monitoring a storage project. In subsequent sections we present a quasi-1D mathematical description of CO2 flux using the “leaky conduit” model. The leaks correspond to permeable formations intersected by the conduit. A “leakoff coefficient” is used to control the rate of leakage. We describe a method for estimating these coefficients from the properties of the formations. To test whether these idealizations are reasonable, we carry out simulations of the full physics of the problem in a 2D domain. Quasi-1D Modeling Approach Assumptions. We assume that the CO2 storage reservoir is located at sufficient depth for the carbon dioxide to be modeled as a slightly compressible fluid. Intersecting this storage volume is a fault, either vertical or at a fixed angle to the storage reservoir (Fig. 1). The most stringent assumption of the model is that we only consider the flow of a single fluid, namely CO2, along the fault. Leakage of CO2 from sali

Chapter 13 – Simulating CO2 Storage in Deep Saline Aquifers

This chapter presents the results of compositional reservoir simulation of a prototypical CO 2 storage project in a deep saline aquifer. The objective of the investigation was to better understand and quantify estimates of the most important CO 2 storage mechanisms under realistic physical conditions. Simulations of a few decades of CO 2 injection followed by 10 3 -10 5 years of natural gradient flow were done. The impact of several parameters was reviewed, including average permeability, the ratio of vertical to horizontal permeability, residual gas saturation, salinity, temperature, aquifer dip angle, permeability heterogeneity and mineralization. The storage of CO 2 in residual gas emerges as a potentially very significant issue meriting further study. Under some circumstances this form of immobile storage can be larger than storage in brine and minerals.