It is of interest to numerically simulate hydraulic fracturing in block caving as an aid to underground mining. UDECTM software was used to simulate the behavior of a two-dimensional jointed rock mass with a defined undercut under biaxial in-situ stresses. The effect of stress ratio on flow into the joints has been studied as a function of injection distance from the top of the undercut. Given the difference in situ stresses, joints reopen under the induced pressures dominantly parallel with the maximum principal stress, a consequence of work minimization. In addition, the effect of injection distance on the stimulated area has been studied. It seems that there is an effective injection distance beyond which rock mass response remains approximately constant. Applying hydraulic fracturing further from the effective distance would precondition the hard rock but it would take longer injection times, rates or pressures to reach the caved block.
Hydraulic fracturing as a treatment method to aid mining has been suggested for several decades in the coal and metal mining industry. Different applications have been suggested as being potential contributions to safety and economic benefits. Recently, hydraulic fracturing has been applied to precondition rock or to induce caving in hard rock around mines. Fractures during mining are conventionally induced by blasting to help the broken rock mass flow from conditioned stopes under gravity forces. More and more, massive caving processes are used to extract entire ore bodies, involving large-scale rock mass fragmentation through massive stress redistribution, and leading to induced caving and flow for the entire orebody, while trying to reduce the amount of blasting needed and also reduce risks of uncontrolled bursts and inadequate fragmentation. Preconditioning of the rock mass to aid this process via hydraulic fracturing involves pre-weakening of orebodies with low friability that are not caved easily (Vyazmensky et al. 2010 and Rahman et al. 2002). Hydraulic fracturing also provides the possibility of stress relief and redistribution, reduction in the stiffness of rock masses, and other associated effects that can increase rock mass caveability to allow it to cave continuously in a controlled stable manner (Jeffrey et al. 2009).
Shale gas development involves aggressive hydraulic fracturing of a naturally fractured rock mass to generate an interconnected open fracture network with a large internal surface area for gas drainage. Conventional hydraulic fracture design software cannot cope adequately with fracture propagation in naturally fractured rock, and it is not clear what form a better design software environment will take, but activity in a number of directions is taking place. Several preliminary options are discussed herein, along with a review of shale gas occurrence and the geomechanical aspects of its development.
Decades ago, natural gas occurrence was noted during drilling through the naturally fractured black shales of Appalachia (Ohio Shale, Marcellus Shale, Utica Shale – Charpentier et al. 1995) and Texas. However, these fine-grained Naturally Fractured Rocks – NFRs – were considered poor prospects for economic production, despite considerable attention paid to them in the 1980’s and 1990’s by the United States Department of Energy and Gas Research Institute (e.g. Kruuskaa et al. 1998, Curtis 2002). Persistence in their development and the implementation of large volume propped Hydraulic Fracturing (HF) methods in vertical wells led to limited production of the gas in the Antrim Shale (Michigan Basin), Barnett Shale (Fort Worth Basin) and Ohio Shale (Appalachian Basin) during the 1990’s and into the first part of the decade of the 2000’s. Massive improvements in drill bit technology, top-drive drilling rigs, and down-hole steerable drilling motors made the emplacement of horizontal wells >1 km long economical by the late 1990’s. This was followed by development of new well completion techniques – Multi-Stage Hydraulic Fracturing – MSHF – in the period 2000–2008.With these technologies, the “shale gas revolution” had arrived in the United States and Canada, but it was not until about 2010–2012 that the full economic impact was realized.
Abstract: Distributed optical fiber sensors (DOFSs), used initially in structural health monitoring for high-rise buildings and bridges, are attracting attention in the field of underground structures, including mining. Designed for long-term study of deformations, DOFSs are more efficient when installed away from excavation damaged zone (EDZ) in a borehole filled with a grout mixture to measure elastic strain field responses to excavations. The DOFS sensing cable, as a component of a complex compliance system, i.e. rockmass and grout, is being assessed through laboratory work.
A test program is underway to observe DOFS response to various perturbations including strain and joint displacement. Initially, tests on unstrained sensors are performed in order to assess measurement repeatability and noise-to-signal ratio at both local and global scales. Then, the various lengths of the cable, from 1 m down to 1 cm, will be stretched up to 0.5% strain. In other tests, the same lengths of the cable will be exposed to shear displacement, such as might occur in the vicinity of a joint or fault that experiences shear.
The results from these tests will answer uncertainties and questions regarding the scaling factor between straining sections over a full sampling window, i.e. spatial resolution, and a partial sampling window, i.e. validity of calibration factors provided by the supplier, and assessing effects of coating and plastic protective layers of the sensor. Issues such as shear deformation responses of cable and bending direction of the cable are being evaluated.
Initial results on unstrained cable to assess measurement repeatability showed variability in length assessment between successive readings. This variability particularly impacts the data interpretation from the strain sensors since these sensors present locally large Brillouin frequency gradients which results in locally large variability in differential readings. Our detailed experimental results will be presented in the paper.
Kaiser, Peter K. (Centre for Excellence in Mining Innovation) | Valley, Benoît (Centre for Excellence in Mining Innovation and ETH) | Dusseault, Maurice B. (University of Waterloo) | Duff, Damien (Centre for Excellence in Mining Innovation)
Madjdabadi, B.M. (Civil Engineering Department, University of Waterloo) | Valley, Benoit (Geomechanics Research Centre, MIRARCO - Mining Innovation) | Dusseault, Maurice B. (Earth and Environmental Sciences Department, University of Waterloo) | Kaiser, Peter K. (CEMI)
Dusseault, Maurice B. (University of Waterloo)
In enhanced oil recovery, steam injection involves high stresses, pressures, temperatures and volume changes. Traditional reservoir simulation fails to predict associated transient ground surface movements because it does not consider coupled geomechanical effects. We present a fully-coupled, thermal half-space model using a hybrid DDFEM method, in which a simultaneous finite element method (FEM) solution is adopted for the reservoir and the surrounding thermally affected zone, and a displacement discontinuity (DD) method used for the elastic, non-thermal zone. This approach provides transient ground surface movements in a natural manner.
The Lower Fars (LF) sandstone reservoir in Northern Kuwait( NK) is probably the single largest accumulation of heavy oil (HO, µ > 100 cP) in Kuwait, containing somewhere in the range of 12-15 Bb distributed over an area of ~1000 km2 northwest of Kuwait City against the Iraqi border. There are other heavy oil accumulations in Kuwait, mainly in naturally fractured carbonate strata, but they are of smaller size and of lower quality. Although a small resource in comparison to Canadian and Venezuelan HO resource, the Lower Fars reservoir nonetheless represents a significant fraction of Kuwaiti resources.
Compared to viscous oil deposits elsewhere in the world, the LF asset is shallow, of generally higher porosity and permeability, and of lower viscosity with a significant variation in fluid properties with depth and with location in the large reservoir. These characteristics will lead to the deployment of a number of production technologies similar to but somewhat different from Canadian experience, with the potential for generally greater recovery factors and lower costs than in Canada. Furthermore, a general situation is emerging in the Kuwait region that may be unusually favorable for heavy oil development, and these positive factors include:
· Availability of diluents and natural gas for production process,
· Capital availability for upgrading investment,
· Sources of low-cost heat.
This confluence of excellent reservoir properties, existing commercialized technologies with a reasonable history of commercialization, a good infrastructure, and supportive emerging supportive conditions will make the development of the LF a less costly venture than comparable cases in Canada and Venezuela.
In this paper the latest studies in reservoir evaluation and various screening techniques for selection of optimal production technologies will be presented. We will revisit the concept of deliberate sequencing of processes, planning in advance for such strategies. We will even speculate on how local heat sources might be integrated into production processes.
The recently proposed Kuwait Institute for Scientific Research (KISR) Strategy 2030 program, presents a new vision and mission for KISR to become an " R&D Center of Excellence?? focusing on innovation to support KOC's requirements and technology leadership. As part of this strategy a Research Program (RP) for development of Heavy Oil (HO) reservoirs and upgrading technology will be established in KISR.
The challenge for this program is to assist KOC in the development and production of heavy oil reservoirs by identifying and developing modern recovery technologies for different reservoirs in Kuwait in an environmentally appropriate manner. Our Approach is a practical application of new technology and knowledge that can be taken from the laboratory and deployed in the field. In this paper the latest studies in reservoir evaluation and various screening techniques for selection of optimized production technologies for HO will are presented.
For about 25 years the oil industry has disposed of waste into the deep underground (drill cuttings, mud chemicals, sludge, produced water and sand, crude-contaminated soils, etc.). Small-scale annular injection projects are typical for disposing of the waste produced in single drilling campaigns, but large-scale projects are also ongoing using dedicated injection sites, where oil companies are able to dispose up to hundreds of thousands of tonnes of waste every year.
Most commonly, the technique consists of preparing a slurry comprising waste liquid and finely divided solid waste grains, and injecting it through wells into the deep underground. To ensure injectivity, the operations take place at pressures sufficient to induce hydraulic fractures in the target rock. Once injection ceases, pressures decline, fractures close, solid waste particles remain entrapped by stress, and the excess liquid dissipates through porous media flow.
There are two critical feasibility factors. The first is geological suitability: injection should take place in tectonically passive regions into sedimentary strata of high porosity and permeability. The presence of impermeable strata above the injection zone will protect shallow groundwater from contamination with the injected fluids. The second factor is that the injection process is executed with advanced monitoring techniques and periodic well assessment to provide accurate and updated operational control while establishing best operating parameters, minimizing environmental risk, and complying with regulatory needs. This paper discusses these aspects along with suggested guidelines in the context of several field case histories.
If such critical factors are resolved satisfactorily, wastes become isolated permanently with minimum risk to potable water sources, surface watercourses, or the sea. Furthermore, organic waste injection (e.g. human and animal biosolids, organic refuse) will also reduce CO2 emissions, and most of the carbon remains deep underground in solid form, the most secure approach to sequestration.
Deep waste injection is seldom used outside the oil industry; however, there are strong economic and environmental incentives for application to other waste streams. The most desirable stratigraphic conditions are typical of hydrocarbon-containing sedimentary basins where impermeable layers overlying porous and permeable strata have kept hydrocarbons in place for millions of years. Thus, primary candidate sites are likely to be old depleted reservoirs. Also, in a hydrocarbon province, stratigraphic data, operational experience, and technological expertise are available for its implementation.
This paper focuses on deep waste injection potential in new geographical areas, analyzing it as a disposal technique for different municipal and industrial waste streams. Although many of the technical and social issues are valid worldwide, the situation in Europe deserves particular attention:
• The environmental pressure on most European countries is large and increasing because of many densely-populated and heavilyindustrialized areas;
• Public awareness of the need to protect the environment has constantly been growing, driving the European Union toward approval of stricter regulations;
• Many geographical regions corresponding to the major sedimentary basins and flatlands in Europe are likely to be suitable;
• It is cost-effective compared to current disposal techniques used in Europe for most municipal and industrial waste streams;
• Despite no specific country-scale regulations to date, European Union law already includes deep underground injection as a permitted waste disposal method.