Günter Zimmermann

Integrated log interpretation in the German Continental Deep Drilling Program: Lithology, porosity, and fracture zones

Well logs, aquired in the two scientific drill holes of the German Continental Deep Drilling Program (KTB), provide continuous records of physical and chemical data of the metamorphic rocks penetrated. The 4-km-deep pilot hole was almost completely cored, enabling the well logs to be calibrated with regard to rock composition and structural features derived from laboratory analysis of cores. The observed relationships were transferred to the 9101 m deep, nearly uncored, main hole to reproduce in detail the lithology and to estimate physical properties from the logs. Synthetic lithological profiles were constructed for the pilot hole and the main hole by applying the electrofacies concept adapted to the crystalline environment. These profiles provide information on lithostratigraphy, alteration, cataclastic overprint, and petrogenetic features. Cross-hole correlations of these profiles reveal identical rock sequences for large sections of the drilled, metamorphic basement in both holes, in which the primary differences between the protoliths are largely preserved. Multivariate statistical methods were used to determine porosity depth functions from log responses. Linear as well as multilinear regression yielded continuous porosity profiles for both boreholes. Factor analysis was used to extract a parameter interpreted as a fluid and fracture indicator. Comparison of the porosity profiles with lithological information from log, core, and cuttings data revealed two different origins of increased porosity. Rock porosity and permeability are not only related to discrete planar discontinuities such as faults and fractures but also to more extensive zones of intense rock alteration where considerable matrix porosity occurs.

Numerical Investigation on Stress Shadowing in Fluid Injection-Induced Fracture Propagation in Naturally Fractured Geothermal Reservoirs

In low permeability shale reservoirs, multi-stage hydraulic fracturing is largely used to increase the productivity by enlarging the stimulated rock volume. Hydraulic fracture created alters the stress field around it, and affects the subsequent fractures by the change of the stress field, in particular, mostly increased minimum principal stress at the area of subsequent fracturing. This is called stress shadow which accumulates as the fracturing stages advance from toe to heel. Hydraulic fractures generated in such altered stress field are shorter and compact with orientation deviating significantly from the far-field maximum horizontal stress orientation. This paper presents 2D discrete element-based numerical modeling of multi-stage hydraulic fracturing in a naturally fractured reservoir and investigates stress shadowing. The stress shadowing is tested with two different injection scenarios: constant and cyclic rate injections. The results show that cyclic injection tends to lower the effect of stress shadow as well as mitigates the magnitude of the induced seismicity. Another modeling case is presented to show how the stress shadow can be utilized to optimize a hydraulic fracture network in application to Groß Schönebeck geothermal reservoir, rather than being mitigated. The modeling demonstrated that the stress shadow is successfully utilized for optimizing the geothermal heat exchanger by altering the initial in situ stress field from highly anisotropic to less or even to isotropic.

Scale Dependence of Hydraulic and Structural Parameters in the Crystalline Rock of the KTB

Knowledge of rock properties controlling the fluid movement is a basic prerequisite to understand the dynamical processes and the temperature and stress regime of the upper crust. Fracture networks were investigated on different scales to obtain quantitative results of fracture geometry like fracture length, orientation and fracture frequencies. Due to the scale effect, these parameters differ in several orders of magnitude in dependence of the scale of investigation. On the microscopic scale, fluorescent thin sections from cores were analysed and permeability was estimated for 2-D hydraulic networks. On the macroscopic scale, fracture parameters were determined from images of structural borehole measurements. The vicinity of the drill site represents the megascopic scale, where seismic reflectors were assumed as active hydraulic structures for construction of a fracture network. Compiling the fracture densities from all investigated scales and taking into consideration only the networks above the percolation threshold, the fracture length distribution follows a power law with an exponent of-1.9 ± 0.05. Besides the scale differences of the geometric parameters like fracture density and length and the hydraulic parameters like permeability, the connectivity of the networks seems to be a confining characteristic. This is quantitatively described by the percolation parameter and the mean number of intersections per fracture. When assuming a macroscopic hydraulic system at the percolation threshold for the KTB site, the macroscopic mean fracture length can be estimated to approximately 30 m. This stands in agreement with the hydraulic experiments on site

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and hot-dry-rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in biwing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial discrete fracture network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulations suggest that stress state, in situ fracture networks, and fluid type are the main parameters influencing hydraulic fracture network development. Major factors leading to more complex fracture networks are an extensive pre-existing natural fracture network, small fracture spacings, low differences between the principle stresses, well contained formations, high tensile strength, high Young’s modulus, low viscosity fracturing fluid, and large fluid volumes. The differences between 5 km deep granitic HDR and 2.5 km deep shale gas stimulations are the following: (1) the reservoir temperature in granites is higher, (2) the pressures and stresses in granites are higher, (3) surface treatment pressures in granites are higher, (4) the fluid leak-off in granites is less, and (5) the mechanical parameters tensile strength and Young’s modulus of granites are usually higher than those of shales.

Mechanically Induced Fracture-Face Skin--Insights From Laboratory Testing and Modeling Approaches

In context of this work, a new formation damage mechanism is proposed: the mechanically induced fracture face skin (FFS). This new mechanism results from mechanical interactions between the proppants and the reservoir rock, due to the increasing stress on the rock-proppant system during production. Proppant embedment into the fracture face and proppant crushing leads to fines production and may impair the fracture performance. In order to achieve sustainable, long-term productivity from a reservoir, it is indispensable to understand the hydraulic and mechanical interactions in rock-proppant systems. Permeability measurements on sandstones with propped fractures under stress using different flow cells were performed, allowing localizing and quantifying the mechanical damage at the fracture face. The laboratory experiments identified a permeability reduction at the fracture face up to 90 %. The mechanical damage at the rock-proppant interface begins immediately with loading the rock-proppant system and for fracture closure stresses below 35 MPa; the damage is localized at the fracture face. Microstructure analysis identified quartz grain crushing, fines production and pore space blocking at the fracture face causing the observed mechanically induced FFS. At higher stresses, damage and embedment of the ceramic proppants further reduces the fracture permeability. Numerical modeling of the rock-proppant system identified highly inhomogeneous stress distributions in the granular system of grains and proppants. High tensile stress concentrations beneath the area of contact between quartz grains and proppants are observed even at small differential stress applied to the rock-proppant system. These high stress concentrations are responsible for the early onset of damage at the fracture face. Therefore, even low differential stresses, which are expected under insitu conditions, may affect the productivity of a hydraulically fractured well.

Investigation of the undrained poroelastic response of sandstones to confining pressure via laboratory experiment, numerical simulation and analytical calculation

Abstract To describe the poroelastic behaviour of sandstones, two factors have to be considered: the grain structure and the pore volume included. Changes in these two factors through diagenetic processes, tectonic loading or other forces lead to different results. Often external stresses induce a compaction of the rock and, therefore, a reduction of pore volume and an increased fluid pressure. Under undrained conditions, the largest pore pressure response can be observed. Besides the Biot coefficient, the Skempton coefficient (B) is one of the most important variables of elastic rock deformation, as it describes the pore pressure change related to the acting stresses. This study shows three ways of determining the Skempton coefficient and gives evidence of its pressure dependence. First, the undrained poroelastic response of a Bentheimer sandstone sample to confining pressure change was measured. Second, a thin-section micrograph was transferred into a finite-element model, including a discretization of the grain structure and the pore space. Finally, the Skempton coefficient of a linear elastic hollow sphere was calculated to prove the laboratory experiment and the numerical simulation.

Scale dependence of hydraulic and structural parameters in fractured rock, from borehole data (KTB and HSDP)

Abstract Fundamental understanding of the origin, geometry, extension and scale dependence of fluid pathways in fractured rock is still incomplete. We analysed fracture networks on different scales, based on data from fluorescent thin sections and borehole televiewer (BHTV) images, to obtain geometrical network parameters and to estimate fracture permeability in the vicinity of a mantle plume (Hawaii Scientific Drilling Project, HSDP). In the depth interval between 814 and 1088 m below sea-level, we observed microfractures in the fluorescent thin sections, and macroscopic fractures in the corresponding BHTV data from the same depth range. Initial modelling of the microscopic network from the fluorescent thin section taken at 1088 m below sea-level gives a clear indication that in this particular case the preferential hydraulic pathways on the microscopic scale are the microfractures in the olivine crystals. This is the only plausible explanation of high porosity (16.6%, based on core measurement), due to the observed vesicles and the corresponding low permeability of 10 µdarcy. Modelling hydraulic flow and calculation of permeability leads to similar values of permeability of 12.3 µdarcy, assuming a mean fracture aperture of 1 µm and an exponential distribution function of the fractures. Detected structures from BHTV measurements were used to construct a macroscopic stochastic network to simulate the hydraulic flow. We found 337 fractures in the depth section from 783.5 to 1147.5 m below sea-level, which result in a linear frequency of 0.927 m−1. Assuming horizontal layers and constant fracture apertures of 100 µm for all structures, leads to a first estimate of permeability of 77 mdarcy (7.7 × 10−14 m2) in this depth section. In a recent work, we showed that for data from the Continental Deep Drilling Project (KTB), the fracture density versus fracture length follows a power law. First results from the Hawaiian data suggest a similar relationship, despite all of the differences in the lithological conditions between both sites.

Joint Research Project Brine: Carbon Dioxide Storage in Eastern Brandenburg: Implications for Synergetic Geothermal Heat Recovery and Conceptualization of an Early Warning System Against Freshwater Salinization

Brine was a scientific joint-project implemented to accompany a prospective CO2 storage site in Eastern Brandenburg, Germany. In this context, we investigated if pore pressure elevation in a CO2 storage reservoir can result in shallow freshwater salinization involving the conceptual design of a geophysical early warning system. Furthermore, assessments of a potential synergetic geothermal heat recovery from the CO2 storage reservoir and hydro-mechanical integrity were carried out. The project results demonstrate that potential freshwater salinization is strongly depending on the presence and characteristics of geological weakness zones. The integrated geophysical early warning system allows for reliable monitoring of these potential leakage pathways at different spatial and time scales.

Particle Based Discrete Element Modeling of Hydraulic Stimulation of Geothermal Reservoirs, Induced Seismicity and Fault Zone Deformation

Abstract This numerical study investigates seismicity and fault slip induced by fluid injection in deep geothermal reservoir with pre-existing fractures and fault. Particle Flow Code 2D is used with additionally implemented hydro-mechanical coupled fluid flow algorithm and acoustic emission moment tensor inversion algorithm. The output of the model includes spatio-temporal evolution of induced seismicity (hypocenter locations and magnitudes) and fault deformation (failure and slip) in relation to fluid pressure distribution. The model is applied to a case of fluid injection with constant rates changing in three steps using different fluid characters, i.e. the viscosity, and different injection locations. In fractured reservoir, spatio-temporal distribution of the induced seismicity differs significantly depending on the viscosity of the fracturing fluid. In a fractured reservoir, injection of low viscosity fluid results in larger volume of induced seismicity cloud as the fluid can migrate easily to the reservoir and cause large number and magnitude of induced seismicity in the post-shut-in period. In a faulted reservoir, fault deformation (co-seismic failure and aseismic slip) can occur by a small perturbation of fracturing fluid (<0.1 MPa) can be induced when the injection location is set close to the fault. The presented numerical model technique can practically be used in geothermal industry to predict the induced seismicity pattern and magnitude distribution resulting from hydraulic stimulation of geothermal reservoirs prior to actual injection operation.

Evaluating Micro-Seismic Events Triggered by Reservoir Operations at the Geothermal Site of Groß Schönebeck (Germany)

This study aims at evaluating the spatial and temporal distribution of 26 micro-seismic events which were triggered by hydraulic stimulation at the geothermal site of Groß Schönebeck (Germany). For this purpose, the alteration of the in-situ stress state and the related change of slip tendency for existing fault zones due to stimulation treatments and reservoir operations is numerical simulated. Changes in slip tendency can potentially lead to reactivation of fault zones, the related movement can lead to the occurrence of seismic events. In the current numerical study, results obtained based on the thermal–hydraulic–mechanical coupled simulation are compared to field observations. In particular, the study focuses on describing the fault reactivation potential: (1) under in-situ stress conditions; (2) during a waterfrac stimulation treatment; and (3) during a projected 30 years production and injection period at the in-situ geothermal test-site Groß Schönebeck. The in-situ stress state indicates no potential for fault reactivation. During a waterfrac stimulation treatment, micro-seismic events were recorded. Our current evaluation shows an increase of slip tendency during the treatment above the failure level in the direct vicinity of the micro-seismic events. During the projected production and injection period, despite increased thermal stress, the values for slip tendency are below the threshold for fault reactivation. Based on these results, and to prove the applied method to evaluate the observed micro-seismic events, a final discussion is opened. This includes the in-situ stress state, the role of pre-existing fault zones, the adopted criterion for fault reactivation, and a 3D rock failure criterion based on true triaxial measurements.