Ronny Hofmann

Evaluation of variable gas saturation on acoustic log data from the Haynesville Shale gas play, NW Louisiana, USA

Many technical challenges must be overcome to ensure the economic development of a shale gas resource including: (1) making an accurate assessment of gas distribution and saturation, (2) identifying target zones that optimize the impact of hydraulic fracture stimulation and completion, and (3) drilling safe and cost-effective wells. In order to meet these challenges, it is necessary to characterize the physical and mechanical properties of the shales. Sonic logs provide important data about the rock and fluid properties that can be used for this characterization. One motivation for this work was to determine how sonic logs in gas-bearing shales can be used to characterize rock properties, derive mechanical properties, and estimate in-situ stresses.

Estimating permeability from thin sections without reconstruction: Digital rock study of 3D properties from 2D images

We present a new approach for predicting permeability of natural rocks using thin sections. Our approach involves two steps: (1) computing permeability of the thin sections for flow normal to the face, and (2) application of new robust 2D-3D transforms that relate thin section permeability to 3D rock permeability using calibration parameters. We perform step 1 using Lattice-Boltzmann and finite difference schemes, which are memory efficient. We discuss two models to perform step 2. Our two-step approach is fast and efficient, since it does not require reconstruction of the unknown 3D rock using 2D thin section information. We establish the applicability of this new approach using a dataset comprised of LBM-computed permeability of rock samples from various geologic formations, including Fontainebleau sandstone, Berea sandstone, Bituminous sand, and Grosmont carbonate. We find that for sandstones our approach predicts fairly accurate permeability with little calibration. Predicting permeability of carbonates from thin sections is more challenging due to microstructural complexity thus model parameters require more calibration. For general workflow, we propose to first calibrate the proposed models using the available 3D information on the rock microstructure (from microCT, SEM, etc.) and then predict the permeability for rocks from the same geological formation for which only 2D thin sections are available.

Softening of organic matter in shales at reservoir temperatures

The elastic modulus of organic matter can strongly influence the mechanical behaviour of source rocks. Although recent advances have shed crucial light on the mechanical properties of natural organic matter under ambient conditions, the elastic properties of kerogen and bitumen at reservoir temperatures remain poorly constrained. In this paper, we use a novel atomic force microscope technique to measure the changes to organic matter during the heating of an organic-rich shale. Our measurements show that bitumen becomes more compliant with heating and in an experiment during which the temperature was increased from 25 to 225°C, the reduced elastic modulus dropped from 6.3 to 0.8 GPa. In contrast to bitumen, we were unable to discern any significant changes to the elastic modulus of kerogen with increasing temperature. Our results suggest that the temperature dependence of the elastic properties could be used as an additional method to differentiate between bitumen and kerogen in shales. Moreover, our analysis indicates that temperature should be taken into account when modelling the elastic properties of bitumen under reservoir conditions.

A distributed parallel multiple-relaxation-time lattice Boltzmann method on general-purpose graphics processing units for the rapid and scalable computation of absolute permeability from high-resolution 3D micro-CT images

Digital rock physics (DRP) is a rapidly evolving technology targeting fast turnaround times for repeatable core analysis and multi-physics simulation of rock properties. We develop and validate a rapid and scalable distributed-parallel single-phase pore-scale flow simulator for permeability estimation on real 3D pore-scale micro-CT images using a novel variant of the lattice Boltzmann method (LBM). The LBM code implementation is designed to take maximum advantage of distributed computing on multiple general-purpose graphics processing units (GPGPUs). We describe and extensively test the distributed parallel implementation of an innovative LBM algorithm for simulating flow in pore-scale media based on the multiple-relaxation-time (MRT) model that utilizes a precise treatment of body force. While the individual components of the resulting simulator can be separately found in various references, our novel contributions are (1) the integration of all of the mathematical and high-performance computing components together with a highly optimized code implementation and (2) the delivery of quantitative results with the simulator in terms of robustness, accuracy, and computational efficiency for a variety of flow geometries including various types of real rock images. We report on extensive validations of the simulator in terms of accuracy and provide near-ideal distributed parallel scalability results on large pore-scale image volumes that were largely computationally inaccessible prior to our implementation. We validate the accuracy of the MRT-LBM simulator on model geometries with analytical solutions. Permeability estimation results are then provided on large 3D binary microstructures including a sphere pack and rocks from various sandstone and carbonate formations. We quantify the scalability behavior of the distributed parallel implementation of MRT-LBM as a function of model type/size and the number of utilized GPGPUs for a panoply of permeability estimation problems.

Adding geologic prior knowledge to Bayesian lithofluid facies estimation from seismic data

AbstractUsing inverted seismic data from a turbidite depositional environment, we have determined that accounting only for rock types sampled at the wells can lead to biased predictions of the reservoir fluids. The seismic data consisted of two volumes resulting from a (multi-incidence angle) sparse-spike amplitude variation with offset inversion. Information from a single well (well logs and petrological analysis) was used to define an initial set of lithofluid facies that characterized rock type and porefill fluid to emulate a typical exploration setting. Based on our geologic understanding of the study area, we have augmented this initial model with lithofluid facies expected in the given depositional environment, yet not sampled by the well. Specifically, the new lithofluid facies accounted for variations in the mixture type and proportions of shales and sands. The elastic property distributions of the new lithofluid facies were modeled using appropriate rock-physics models. Finally, a geologically co...