Zhixi Chen

An experimental investigation of hydraulic behaviour of fractures and joints in granitic rock

A method of measuring mean mechanical aperture of fractures based on gas volume balance is introduced. The effects of shear displacement and normal stress on mechanical and hydraulic behaviour of fractures are also investigated. The results obtained from tests conducted on granite samples from Olympic Dam (Central Australia) are compared with those calculated from existing shear dilation theories. It is found that hydraulic aperture is considerably narrower than the measured mean mechanical aperture. This highlights the need to consider tortuosity and surface roughness of fractures in the calculation of hydraulic aperture. It is also found that shear dilation angle decreases linearly with increases in confining pressure, as opposed to more rapid decreases predicted by existing empirical models. From the results of this study, a range of data describing the relationships between confining pressure, shear displacements, hydraulic aperture and permeability are presented, which could help to develop stimulation programs for geothermal reservoirs.

Integrated conditional global optimisation for discrete fracture network modelling

This paper presents a methodology to simulate discrete fracture networks for naturally fractured reservoirs by combining statistical and spatial analyses, object-based modelling and conditional global optimisation. The methodology examines and utilises both continuum and discrete fracture information, such as spatial distribution of fracture density, statistical and geostatistical distributions of fracture size and orientation. The output is a network of discrete fractures, with their corresponding details of location, size and orientation. The methodology is illustrated by a case study on the surface fault system in New York region. The results show that it is able to produce discrete fracture network that match closely to the target fault map, even in the case where data are limited. The results show that it is also able to improve results of several recent fracture models, such as integrated stochastic simulations as well as grid-based simulations.

Experimental investigation of shale membrane behavior under tri-axial condition

Abstract Wellbore instability in shale formations is one of the primary problems in oil and gas well drilling. The problem has been traditionally tackled by using oil-based drilling mud. However, this technique is costly and restricted by the environmental regulatory bodies. Recent studies have shown that borehole instability in shales can be managed by controlling the chemical potential of drilling mud. One of the critical issues in this approach is that shales are not ideal membranes. It is essential to understand the nonideal behavior of shale before the wellbore instability problem can be managed by the chemical potential approach. The nonideality of a shale membrane is, in general, a function of the type of the shale being drilled, composition of the formation water in the shale, burial depth of the shale, and chemical composition of the drilling mud used. In this paper, the theory on nonideal membrane was reviewed and identified for the purpose. The mathematical model was validated by experimental results obtained using a real field shale specimen from the Northwest Shelf of Australia. An example is also given to show how the model can be used to manage wellbore instability in shale by controlling the chemical composition of mud. The results of this study can be used as a useful guideline for formulating proper mud to drill troublesome shaly formations.

Effective permeability calculation using boundary element method in naturally fractured reservoirs

Abstract A model is presented to calculate the effective permeability tensor in naturally fractured reservoirs using Boundary Element Methods (BEM). Arbitrary fractures of different scales based on their length are considered. Interface boundary condition is used to model the short fractures as an enhancement of matrix permeability. Long fractures, on the other hand are treated as source/sink in the corresponding blocks. Periodic boundary condition is applied to the grid-block boundaries to calculate the elements of effective permeability tensor. Darcys law and Navier-stokes equation are applied to fluid flow in rock matrix and fractures, respectively. An important feature of this approach is that the fluid flow in matrix-fracture interface is coupled by Poissons equation and fluid flow in the rest of the matrix is formulated by Laplaces equation. This paper also presents an innovative approach to optimization and parallelization of the model by High Performance Computing (HPC) techniques. The model has been validated against analytical results and applied to a typical case where arbitrary fractures of different sizes are assumed within the grid blocks. The effective block permeability tensors can be implemented into a reservoir simulator to calculate fluid flow through the naturally fractured reservoirs.

Practical Application of Hybrid Modelling to Naturally Fractured Reservoirs

Abstract This article presents application of a hybrid method for modelling discrete fracture network in an actual naturally fractured reservoir (NFRs) (Palm Valley, Australia). The hybrid method integrates features of geological, statistical, artificial intelligence, and conditional hierarchical stochastic simulation techniques. Both discrete and continuum fracture information could be utilized, such as statistical distributions of fracture orientations, spatial distributions of fracture density, and discrete multi-fractal dimensions. The final output is a 3D network model of discrete fractures, with their corresponding details of location, size, and orientation. The results show an improvement of the hybrid method over previous fracture models.

Characterizing and Modelling of Fractured Reservoirs With Object-Oriented Global Optimization

Modelling of naturally fractured reservoirs is the first step to develop best scenarios for hydraulic fracture treatment, the design of an optimum production method and to evaluate reservoir potential. This paper reviews the state-of-the-art in current methods; hence, presents an integrated modelling methodology, utilizing object-based modelling, stochastic simulation and global optimization. Firstly, as an object-based model, each fracture is presented and treated as a discrete object. A stochastic simulation is carried out to generate an initial fracture network. An objective function is then formulated as the difference in statistics between the initial network and the target. Semi-variogram and other spatial statistical properties (cross variogram, multi-histogram mean and variogram distance) of fracture parameters are included so that the objective function is able to statistically describe representative field data. Subsequently, we use a global optimization algorithm to optimize the objective function. A case study is performed on an actual outcrop fault map to illustrate the proposed methodologys capacity. The results map the outcrop faults very closely.

A Holistic Approach to the Design and Evaluation of Hydraulic-Fracture Treatments in Tight Gas Reservoirs

This paper presents a comprehensive approach to the design of hydraulic-fracture treatments. accounting for anisotropic stress conditions, rock properties, and the effect of pore-pressure changes caused by production in tight gas reservoirs. This has allowed its, among other opportunities, to design a refracture treatment. The poroelastic model is also coupled with a production-optimization scheme to optimize the design parameters for hydraulic-fracture treatments. A case Study of refracture treatment has been carried out for a typical tight gas reservoir. This Study has shown that the fracture treatment can be optimized successfully to increase the net present Value and/or ultimate gas recovery. This study also has demonstrated that a second fracture treatment can be performed after a period of production from the same treated interval to maintain production without the drilling of additional wells.

Analysis of Time-Dependent Wellbore Stability of Underbalanced Wells Using a Fully Coupled Poroelastic Model

Coupled poroelastic response of formation around wellbore is expected to differ from the classic linear elastic theory when subject to changes in the state of stress. This may lead to redistribution of stress and pore pressure around the wellbore and consequent time-dependant wellbore deformation. These effects could cause delayed wellbore failure, loss of circulation and even the total loss of the well, especially in the case of underbalanced drilling. This paper presents a fully coupled poroelastic model developed for wellbore stability analysis with particular emphasis on fluid flow induced stress changes around wellbore. By using finite element methods, the model is able to simultaneously compute the geomechanical and hydraulic variables. In analogy with the common approach of wellbore stability analysis through initial and infinite time stresses calculation, the model can evaluate transient stress and pressure profiles to demonstrate the behavior of a wellbore throughout its history. This allows us to widen the safety mud weight window which leads to reduced drilling time and costs. The time of failure can be predicted by using modified Mohr-Coulomb criteria for breakout failure and tensile failure criteria for fracture. Thus, the coupled poroelastic approach can examine the factors influencing the wellbore stability more accurately than linear elastic method. The model was used to analyse wellbore stability in different formation types, stress conditions and drilling situations. Time-dependent shear stress distributions are presented so that they can be compared with shear strength of these rocks at different depths to select appropriate mud weights for underbalanced drilling.

Modeling Time-Dependent Pore Pressure Due to Capillary and Chemical Potential Effects and Resulting Wellbore Stability in Shales

During drilling operations, the mud filtrate interacts with the pore fluid around the wellbore and changes pore pressure by capillary and chemical potential effects. Thus the change in pore pressure around borehole becomes time-dependent, particularly in extremely low permeability shaley formations. In this paper, the change in pore pressure due to capillary and chemical potential effects are investigated experimentally. Analytical models are also developed based on the experimental results. A wellbore stability analysis model incorporating the time-dependent change in pore pressure is applied to a vertical well in a shale formation under normal fault stress regime.

Effect of cap rock thickness and permeability on geological storage of CO2: laboratory test and numerical simulation

Geological storage of CO2 is considered widely as an efficient method of mitigation of greenhouse gas emission. CO2 storage mechanism includes structural trapping, residual gas trapping, solubility trapping and mineral trapping. The shale cap rock acts as a seal for the storage when CO2 accumulates at the top of the reservoir. The injected CO2 may migrate through the cap rock under buoyancy force or pressure build-up which depends on the seal capacity of the cap rock. As a result, the effectiveness of containment of injected CO2 in the reservoir is largely dependent on the migration rate of CO2 through the cap rock. This paper investigates the effects of CO2 leakage through cap rock by a combination of experimental studies and numerical simulation. Firstly, experimental measurements on shale core samples collected from Australian cap rocks were conducted to determine properties, such as capillary pressure, pore size distribution and permeability. Based on the measured cap rock properties, the effect of thickness and permeability of cap rocks on CO2 leakage was studied using a commercial compositional simulator. Experimental results show that the permeabilities of the shale samples measured by transient pulse technique range from 60 to 300 nD; a non-Darcy calibration factor which equals the ratio of the measured permeability divided by 1000, is identified for samples with permeability lower than 1000 nD. Numerical simulation results show that the largest leakage of CO2 through the seal (cap cock) is about 7.0% with seal thickness of 3m and vertical permeability of 90 nD; both shale thickness and permeability affect the CO2 leakage significantly; with a given seal permeability, the leakage rate has a power relationship with shale thickness.