Fault permeability models for geothermal doublet designs

The occurrence and properties of natural faults and fractures in geothermal reservoirs are key in determining reservoir flow properties, and thereby the performance of geothermal doublets placed in fractured reservoirs or in the vicinity of fault zones. In this paper, an analytical model is presented that describes the 3D non-isotropic permeability of a geothermal reservoir around a major fault zone, taking into account typical fault architectures consisting of a fault core, a damage zone and surrounding intact reservoir matrix. The sensitivity of model predictions to orientations of sedimentary layers, damage zone fractures and fault core is analysed for typical permeability contrasts and dimensions of intact reservoir, damage zone fractures and fault core. The model can be used to determine optimum orientation of geothermal doublets around fault zones, taking into account the distribution and characteristics of faults, fractures and sedimentary layering. Implications for optimizing the design of geothermal doublets placed in the vicinity of large fault zones are given

Discrete modeling of the long term integrity of fault- and top seals at CO² storage sites

The long term integrity of fault and top seals at CO2 storage sites can be affected by chemical reactions of CO2-rich fluids with fault- or caprock as altered rock mechanical properties in combination with changed stress conditions may result in fault reactivation and fracture initiation or propagation. The mechanical properties of fault- or caprock can be significantly altered if reaction products with different volume and geomechanical properties are produced. Considering the low permeability of seals, a positive feedback between reactive flow of CO2-rich fluids and fracture propagation is critical for this to occur. Such coupled chemical- hydromechanical processes are difficult to investigate using field examples or laboratory experiments as reaction kinetics are generally slow

Polymer-gel remediation of CO2 migration through faults and numerical simulations addressing feasibility of novel approaches

Subsurface CO2 storage has been identified as one of the key methods to reduce the emission of CO2 to the atmosphere. Remediation or mitigation of unwanted migration from potential storage sites requires novel approaches for which feasibility is yet to be demonstrated. This study focuses on a solution to mitigate CO2 migration through naturally occurring faults, using a polymergel to drastically reduce the permeability of the fault. The radius of influence of the polymer injection is extended by using hydraulically stimulated fractures to transport the sealant to the leaking area. Reservoirs eligible for CO2 storage generally exhibit relatively high permeability and consequentially high leak-off of frac fluids. Therefore, the extent of hydraulic fractures is expected to be limited. Faults and fractures may be surrounded by a damaged zone with a permeability that is higher than the reservoir (up to 10 times). Considering the extra permeability of the damaged zone, the surface covered by the sealant may be extended by another 20-40%. Current results shows that this technique is technically feasible (with proper choices of polymer-gel and treatment) to mitigate CO2 leakage through a leaking fault

Assessing the short-term and long-term integrity of top seals in feasibility studies of geological CO2 storage

The geomechanical effects of past hydrocarbon production and subsequent CO2 injection in depleted gas reservoirs were evaluated as a part of several recently accomplished feasibility studies of CO2 storage in the Netherlands. The objectives of geomechanical studies were to assess the mechanical integrity of a reservoir-seal system, i.e. the containment, and the induced ground movement, aseismic and seismic. Geomechanical numerical models of the candidate sites make it possible to investigate and quantify production- and injection-induced stress changes in and around the reservoir. Numerical models reveal, as illustrated by a case study presented, that the side seal and the boundary faults at the edges of reservoir compartments represent weak spots where production-induced mechanical damage and fault re-activation will first occur. Possible permeability enhancement resulting from local seal damage and fault slip can provide the initial pathways for CO2 penetration into the seals enhancing fluid-rock chemical interactions. The long-term effects of chemical reactions on the strength of a sample of representative anhydrite caprock indicate that the strength is reduced by one quarter after 50,000 years of exposure to CO2

Addressing Uncertainties in Estimates of Recoverable Gas for Underexplored Shale Gas Basins

Uncertainties in upfront predictions of hydraulic fracturing and gas production of underexplored shale gas targets are important as often large potential resources are deduced based on limited available data. In this paper, uncertainties are quantified by using normal distributions of different input parameters in wellbased models for hydraulic fracturing and gas production. Series of simulations are performed to determine variations in properties of hydraulic fractures and gas production due to uncertainties in geological input parameters (e.g., rock mechanical properties and reservoir permeability) and due to variation in treatment schedules (e.g., injection volumes and fluid type). Relations between stimulated reservoir volume, cumulative gas production, spacing of wells, fracturing stages along horizontal well sections, injection volumes and rock properties are derived from the simulations. The Posidonia Shale Formation in the South of the Netherlands (West Netherlands basin) is used as a demonstration field case to illustrate the approach. By addressing uncertainties in input parameters, more realistic assessment of cumulative gas production can be made. Relations between key parameters such as number of frac stages and cumulative gas production can be used to derive the optimum design of frac jobs as well as optimum placement of frac stages

Numerical modelling of the mechanical and fluid flow properties of fault zones - Implications for fault seal analysis

Existing fault seal algorithms are based on fault zone composition and fault slip (e.g., shale gouge ratio), or on fault orientations within the contemporary stress field (e.g., slip tendency). In this study, we aim to develop improved fault seal algorithms that account for differences in fault zone composition as well as deformation conditions under which the fault zone developed. The influence of composition and deformation conditions on the fluid flow properties of fault zones is investigated using discrete element simulations and laboratory experiments (cf. companioning paper by Giger et al.) of samples consisting of a low-permeability clay or shale layer, embedded in porous sandstone. A combination of discrete element and finite difference models is used to upscale the results and investigate the evolution of fault zone architecture and fluid flow properties of outcrop-scale faults. The fault seal algorithms are tested in a case study using finite element models of reservoir-scale faults. ExxonMobil; Igeoss; RDR; Shell; Total; Wintershal

Model calibration on cement experiments at realistic CO2 storage conditions

Large scale implementation of CO2 storage can significantly reduce emission of greenhouse gasses into the atmosphere. However, safe and long-term containment of CO2 in storage reservoirs must be ensured. Wellbores in the subsurface present possible leakage pathways for CO2 to the surface and hence wellbore cement reactivity is of major concern. Previous experimental studies of cement reactivity often use high brine to cement ratios which may lead to overestimations of the rate of cement alteration. We aim to study cement reactivity under more realistic CO2 storage conditions. Limited brine is used to represent a wellbore environment with brine mainly present in pore space. The experimental results show a cease or significant reduction of reaction progression after 7 days due to saturation of the fluid. This inhibits further cement dissolution and re-dissolution of secondary calcite. The observed reaction zones are matched by geochemical modeling, showing from core to rim: unreacted cement (zone A), portlandite dissolution and increased porosity (zone B), major calcite and reduced porosity plus minor ferrihydrite precipitation (zone Ci) and minor calcite precipitation (zone Cii). The calibration of the geochemical model aids the development of an accurate reactive transport model for long-term cement alteration and integrity prediction

Evolution of Clay Smears and Associated Changes in Fault Transmissibility Using a New Direct Shear Fluid Cell

A new type of fluid cell has been developed to allow for direct shear deformation of very large and cohesive rock samples under sealed conditions. Rock samples consist of a low-permeability clay or shale layer, which is embedded in porous quartz sandstone to mimic a reservoir-seal pair. The cell is specifically designed to monitor changes of fault permeability, both across and along the evolving rupture surface, to displacements equivalent to several times the thickness of the argillaceous layer (i.e. SSF>6, c.f. Lindsay et al., 1993), and under stress conditions typical for burial depths of up to 2000 m. We present the general concept of the new testing equipment, and provide structural and flow data of evolving clay smear structures at controlled physical conditions. The results of the analogue experiments are integrated into a numerical modelling study (cf. companion paper by Ter Heege et al.) in an attempt to upscale our findings to reservoir conditions. ExxonMobil; Igeoss; RDR; Shell; Total; Wintershal

Review of induced seismicity in geothermal systems worldwide and implications for geothermal systems in the Netherlands

Geothermal energy is a viable alternative to gas for the heating of buildings, industrial areas and greenhouses, and can thus play an important role in making the transition to sustainable energy in the Netherlands. Heat is currently produced from the Dutch subsurface through circulation of water between two wells in deep (1.5–3 km) geothermal formations with temperature of up to ∼100 °C. As the number of these so-called doublets is expected to increase significantly over the next decades, and targeted depths and temperatures increase, it is important to assess potential show-stoppers related to geothermal operations. One of these potential hazards is the possibility of the occurrence of felt seismic events, which could potentially damage infrastructure and housing, and affect public support. Such events have been observed in several geothermal systems in other countries. Here we review the occurrence (or the lack) of felt seismic events in geothermal systems worldwide and identify key factors influencing the occurrence and magnitude of these events. Based on this review, we project the findings for seismicity in geothermal systems to typical geothermal formations and future geothermal developments in the Netherlands. The case study review shows that doublets that circulate fluids through relatively shallow, porous, sedimentary aquifers far from the crystalline basement are unlikely to generate felt seismic events. On the other hand, stimulations or circulations in or near competent, fractured, basement rocks and production and reinjection operations in high-temperature geothermal fields are more prone to induce felt events, occasionally with magnitudes of M > 5.0. Many of these operations are situated in tectonically active areas, and stress and temperature changes may be large. The presence of large, optimally oriented and critically stressed faults increases the potential for induced seismicity. The insights from the case study review suggest that the potential for the occurrence of M > 2.0 seismicity for geothermal operations in several of the sandstone target formations in the Netherlands is low, especially if faults can be avoided. The potential for induced seismicity may be moderate for operations in faulted carbonate rocks. Induced seismicity always remains a complex and site-specific process with large unknowns, and can never be excluded entirely. However, assessing the potential for inducing felt seismic events can be improved by considering the relevant (site-specific) geological and operational key factors discussed in this article