5Hydraulic fracturing is extensively used to develop unconventional reservoirs, such 6 as tight gas, shale gas and shale oil reservoirs. These reservoirs are often naturally 7 fractured. Presence of these natural fractures can have beneficial or detrimental 8 effects on the outcome of hydraulic fracturing operation. A proper study is 9 required to characterize these formations, and design a suitable hydraulic 10 fracturing operation. 11 112Reservoir rock may contain imperfections such as faults, joints, natural fractures 113 and so on. Simulating these rocks in Discrete Element Method (DEM) based 114

Hydraulic fracturing technique has been widely used in many cases to enhance well production performance. In particular, this technology is proven to be the most viable technique for the oil and gas production from unconventional reservoirs. Accurate prediction of fracture initiation and breakdown pressure is vital for successful design of Hydraulic Fracturing operation. Methods of predicting these pressures include Analytical analysis, Field experiments, laboratory experiments and numerical simulations. Despite great achievements in the area of analytical analysis, they often failed to represent the true reservoir case, and consequently are found to be erroneous. Field tests such as mini-frac test are the best method for prediction of initiation and breakdown pressure. However, these tests are very limited due to their costs and are not very suitable for sensitivity analysis. Controlled laboratory tests seem to be the best option for predicting initiation and breakdown pressures. Test parameters such as fracturing fluid properties and principal stresses can be controlled with great precision to achieve accurate results. However, same as field tests, laboratory experiments are expensive. Core samples are limited and are expensive. Coring operation can take 4 to 5 days of rig time to take a 90 ft core. Geomechanical tests can take up to three days of a laboratory technician time per sample. Consequently, this will limit the number of tests to be done, and as a result it causes limitations on the conclusions that can be drawn from these tests. Simulation studies on the other hand do not have these limitations and can be used for as many times as desired to perform sensitivity analysis. This paper presents a simulation model that is based on distinct element method. It is used to study the fracture initiation and breakdown pressure during hydraulic fracturing tests. The accuracy of the model was justified through comparison between laboratory experiments and numerical simulation. Four sandstone samples from two different sandstone types and a synthetic cement sample were used in the experimental studies. The tests were performed in True Tri-axial Stress Cell (TTC) with the capability to inject fluid into the samples. Simulation results demonstrate good agreement with experimental results. Fracture propagation path was found to be very similar. Fractures propagated in the direction of maximum horizontal stress.

Many analytical and numerical methods have been developed to describe and analyse fluid flow through the reservoir's porous media. The medium considered by most of these models is continuum based homogeneous media. But if the formation is not homogenous or if there is some discontinuity in the formation, most of these models become very complex and their solutions lose their accuracy, especially when the shape or reservoir geometry and boundary conditions are complex. In this paper, distinct element method (DEM) is used to simulate fluid flow in porous media. The DEM method is independent of the initial and boundary conditions, as well as reservoir geometry and discontinuity. The DEM based model proposed in this study is appeared to be unique in nature with capability to be used for any reservoir with higher degrees of complexity associated with the shape and geometry of its porous media, conditions of fluid flow, as well as initial and boundary conditions. This model has first been developed by Itasca Consulting Company and is further improved in this paper. Since the release of the model by Itasca, it has not been validated for fluid flow application in porous media, especially in case of petroleum reservoir. In this paper, two scenarios of linear and radial fluid flow in a finite reservoir are considered. Analytical models for these two cases are developed to set a benchmark for the comparison of simulation data. It is demonstrated that the simulation results are in good agreement with analytical results. Another major improvement in the model is using the servo controlled walls instead of particles to introduce tectonic stresses on the formation to simulate more realistic situations. The proposed model is then used to analyse fluid flow and pressure behaviour for hydraulically induced fractured and naturally fractured reservoir to justify the potential application of the model.

Shale oil and gas reserves became an important source of energy and their development can increase fossil fuel source. The shale exploration activities have been growing very fast worldwide. However, shale oil and gas production differs from conventional reservoirs in many ways due to its underlying complexities associated with reservoir rock and petro-physical properties as well as extremely low permeability. While massive hydraulic fracturing through horizontal well completion for commercial production of shale oil and gas is paramount, there are many development challenges in regards to understanding of hydraulic fracture propagation behaviour, and its potential impact on fluid flow as required to accurately assess the production performance. The principle mechanism of hydraulic fracture propagation behaviours in shale formation is not well documented. In addition the shale formation is very heterogonous in nature, especially in vertical direction. The fracture propagation behaviour of rock strongly depends on rock mechanical properties, far field stress state and orientation and anisotropies present in the formations such as bedding. This paper presents results of numerical simulation, where shale rock samples are subjected to tensile, uni-axial compression and confined compression tests; and their behaviour are studied. In the first stage, mechanical properties of the simulated samples are calibrated against mechanical properties of two oil shales considered from western US to get micro-mechanical properties that define the samples in the PFC2D. In the second stage these micro-mechanical properties are used to simulate two kinds of rock, one of which has a vertical heterogeneity and the other has lateral heterogeneity to study the effect of fissility on mechanical properties measured in different directions.