Raffaldi, M. J. (National Institute for Occupational Safety and Health) | Seymour, J. B. (National Institute for Occupational Safety and Health) | Abraham, H. (National Institute for Occupational Safety and Health) | Zahl, E. (Contractor) | Board, M. (HeclaMining Company)
ABSTRACT: Underhand cut-and-fill mining has allowed for safe extraction of ore in many mines operating in weak rock or highly stressed, rockburst prone ground conditions. However, design of safe backfill undercuts poses unique geotechnical challenges that must be addressed by these operations. Hecla Mining Company and the Spokane Mining Research Division of the National Institute for Occupational Safety and Health have worked collaboratively for several years to better understand the geomechanics of cemented paste backfill (CPB) and thereby improve safety in underhand stopes. This work has included a series of laboratory strength studies and an extensive in situ backfill instrumentation program to monitor long term stope closure and resulting stress in the backfill. The fill must be strong enough to resist flexural failures, but the large stope closures (5 to 10 cm) that occur during undercutting also require the fill to have significant residual strength in order to remain stable after the elastic strain limit has been exceeded. This paper provides an overview of underhand-cut-and-fill mining with CPB as practiced at the Lucky Friday Mine, the collaborative research that has been undertaken with emphasis on the instrumentation and monitoring program, and technical insight that has been gained through this work.
Backfilling has allowed for safe extraction of ore in many mines operating in weak rock or rockburst-prone ground conditions. In the Coeur d’Alene mining district of northern Idaho, cut-and-fill mining methods have historically been used to mine narrow, steeply dipping veins of silver-lead-zinc ore (Blake and Hedley, 2003; Williams et al., 2007). At the Lucky Friday Mine, the use of cemented paste backfill (CPB) in conjunction with mechanized underhand cut-and-fill mining methods has reduced the number of injuries and fatalities caused by mining in deep, high-stress, rockburst-prone ground conditions, greatly improving the safety of underground miners (Peppin et al., 2001; Pakalnis et al., 2005).
Although the use of backfill has a sound safety record, implementation of a backfilling program is not without risk and requires technical oversight, particularly in underhand cut-and-fill mining operations where employees work directly beneath cemented backfill. Design of safe backfill undercuts poses unique geotechnical challenges that must be addressed.
In this study, rockbolts made of polypropylene random copolymer (PP-R) material were assessed as an alternative to steel split sets in a series of experimental studies that included both laboratory and field-scale tests. PP-R tubes and typical steel split sets were compared by means of static loading (pull and shear), impact loading, corrosion, diametric compression, insertion into drill-holes, and creep tests. Despite the advantages of PP-R; being a noncorrosive material, being shaped by the roughness of drill-hole surfaces, and having ideal support reactions because of high resistance to crack propagation, strain relaxation was found to be a considerable problem with the PP-R tubes inserted into the drill-holes. The results suggest that further work should be undertaken to develop new bolts using PP-R tubes instead of steel split sets.
Split set rockbolts are popular, especially in the mining industry, as a result of their advantages such as practical application, ability to start carrying load without waiting for curing of the grout materials, and good load-bearing capacity despite high deformation. However, underground water can substantially affect steel materials and decrease their load-bearing capacity, especially with long contact times and acidic groundwater conditions (Hoek, 2006; Komurlu and Kesimal, 2015; Hassel and Villaescusa, 2005). The two main factors affecting the frictional load-bearing capacity of the split sets are the normal stress on the drill-hole surface and the coefficient of friction at the contact interface between the bolt and drillhole surfaces (Li, Stjern, and Myrvang, 2014; Heerden 2007; Qingliang et al., 2013; Perras, Diederichs, and Besaw, 2014). Although a rigid rockbolt material is advantageous as the normal stress on the friction surface is supplied due to the decrease in the slit width and diameter of the bolt inserted into the drillhole, a rigid surface prevents the bolt from being shaped by the roughness of the drill-hole surface, which decreases the coefficient of friction. Rockbolt loading mechanisms resulting from rock mass deformation can be divided into axial and shear loading types. The rockbolts are exposed to both axial and shear loading as the rock mass deforms. The frictional load-bearing capacity plays an important role in changing the support reactions under both shear loading and the axial loading conditions (Pellet and Egger, 1996; Srivastava and Singh, 2014; Oreste and Cravero, 2008; Ranjbarnia, Fahimifar, and Oreste, 2016; Garga and Wang 1993).
The Piceance Basin is located in western Colorado and covers an area of about 7,100 square miles1. A spoon-shaped basin, sediments reach a maximum depth of about 20,000 feet near the central portion, and encompass rocks ranging in age from Tertiary to Precambian. The basin is bounded by outcrops on the east, west and south, and by uplifts that separate it on the north from the Sand Wash Basin and on the northwest from the Uinta Basin. There are massive tertiary intrusives – laccoliths and volcanics – on the southeastern portion of the basin that have elevated the heat flow there and a massive basaltic flow extended west across a portion of the central basin to form the caprock of the Grand Mesa area. Figure 1 is a geologic map of the Piceance Basin in western Colorado1.
Oil and gas exploration in the Piceance Basin dates to the early 1900’s, with the discovery of the Rangely field in the northwest portion of the basin. With the exception of Rangely and a few other small fields, the basin is dominated by wells that produce natural gas. Oil and gas production from the Piceance Basin Mancos was first established in the Rangely field area, as well2. To date, about 30,000 wells have been drilled and completed in the basin, and the vast majority of those that are active, about 15,000 wells3, are producing from the Upper Cretaceous Williams Fork formation sands of the Mesaverde Group, in the central portion of the basin
Mancos Exploration to Date
Gas production was established from the Mancos B sand along the western flank of the basin, an area known as the Douglas Creek Arch, that separates the Piceance and Uintah basins, near the Colorado-Utah state line. The Mancos B sand is a sandy interval in the upper portion of the massively thick Mancos Group shale. In May 2001, WPX Energy began gas production from the lower portion of the Mancos shale in the central portion of the basin, in its vertical Vassar Heath RMV 229-27 well, at Section 27-T6S-R94W, in the Rulison Field.
To date, about 120 Mancos shale oil and gas wells have been drilled, completed and placed into production, not including the aforementioned Mancos B sand wells located along the Douglas Creek Arch and the wells in the Rangely field area. About 56 of these wells are vertical completions, and about 64 are horizontal completions. Figure 2 shows the total production from these wells, along with the Nymex price of natural gas. Note that exploration for Mancos shale gas wells began around the time that Nymex natural gas prices began to decline, and that since gas prices reached a low in early 2016, Mancos development has been limited to a few wells per year.
Xu , Guangping (Schlumberger-Doll Research and Sandia National Laboratories) | McCormick , David (Schlumberger-Doll Research) | Herron , Michael (Schlumberger-Doll Research) | Cheshire , Stephen (EXPEC Advanced Research Center) | Al-Salim , Ahmed (EXPEC Advanced Research Center) | Almarzouq, Anas (EXPEC Advanced Research Center)
Mineralogy is important in the evaluation of reservoir quality and completion quality, and thus mineral modeling is of great interest to the industry. The inversion of major-element data from either XRF or nuclear spectroscopy tools to obtain mineralogy logs is a common approach to the interpretation of these data. The inversion method requires one to take into account all major minerals in the samples, which is often challenging to achieve with high accuracy and precision. An alternative approach, forward mineral modeling, uses a limited calibration dataset to derive mineral composition from elemental abundance.
This paper uses a forward-mineral-modeling method to correlate mineral content with all eight major elements (Si, Al, Ca, Mg, Na, K, Fe, and S), in which each individual mineral or a group of minerals is solved independently. The coefficients between mineral and element are obtained through the local calibration. This local calibration method can solve for most of the minerals sought even in situations where some minerals cannot be separately measured with confidence, such as illite and smectite from XRD measurements.
We present a calibrated algorithm using least-squares regression that is optimized by regularization and singular value decomposition applied to a set of samples from the Lower Silurian Qusaiba Member of the Qalibah Formation of Saudi Arabia. The optimized algorithm estimates mineral composition using elemental concentrations from either core or log measurements. With as few as 10 representative samples in the calibration dataset, the optimized algorithm has the ability to predict minerals with an accuracy of a few percent.
Mineralogy affects many petrophysical parameters including porosity, permeability, water saturation, and attributes related to rock strength, which are crucial for evaluating reservoir and completion quality of potential reservoir rocks. The mineralogy of unconventional hydrocarbon shale reservoirs is more complex, but has been less extensively characterized than conventional sandstone and carbonate reservoirs. For unconventional reservoirs, the common industry practice is to measure mineralogy on a set of selected samples to calibrate petrophysical data. The mineralogy can also be estimated from geochemical logging data.
"Litigation against unconventional gas producers; lessons from the US experience."
Richard M Lightfoot, Casconsult Pty Ltd
In North America, exploration and production of oil and gas from unconventional sources principally shale, but also tight sandstones and coal seams – is more developed than elsewhere in the world. The presence of large shale, tight gas, and coal seam gas reserves has led to exploration throughout the world.
In Australia, the unconventional gas industry is most developed in Queensland, is seeking to expand in New South Wales and South Australia, and is prospective in Western Australia the Northern Territory, and, to a much lesser extent Victoria.
In the light of the US experience, which has included claims of mechanical failures and inappropriate waste treatment and disposal, leading to groundwater contamination, induced seismicity and hazardous fugitive emissions, government and scientific agencies have produced thousands of studies of the perceived benefits and risks associated with the gas.
In each jurisdiction where unconventional gas extractions has been proposed, governments have been developing legislative regimes for resource allocation and for the managing of risks, through statutes, regulations, standard, and codes of practice.
In the USA, landowners and other citizens who believe that unconventional gas extraction has caused damage to land, water, human and animal health, have resorted to ligation seeking to recover damages, principally by bringing tortuous claims in negligence, nuisance and trespass. In some jurisdiction, actions have also been based on strict liability and legislated rebuttable presumptions of liability.
The paper summarises some cases brought in the USA, to identify the basis of the claims and to analyse their outcomes. In particular, claims brought in tort, and the potential for such claims brought in Australia must be considered.
All sections of the Unconventional Gas Industry need to become aware of their continuing responsibilities. Corporations require an intimate knowledge of the law, its interpretation and the need to minimise exposure to financial, environmental and health risks.
This paper describes a numerical investigation of hydraulic fracturing in oil sands during cold water injection. Previous studies have shown that hydraulic fracturing in unconsolidated or weakly consolidated sandstone reservoirs is highly influenced by the low shear strength of these materials and is quite different from competent rocks. As such, existing classical hydraulic fracture models are incapable of predicting the fracturing process of weak sandstone reservoirs. This paper presents a numerical tool to simulate hydraulic fracturing in oil sands and weak sandstone reservoirs. A smeared fracture approach is adopted in the simulation of tensile and shear fracturing in oil sands. The model incorporates various phenomena expected in hydraulic fracturing, including poroelasticity and plasticity, matrix flow, shear and tensile fracturing and concomitant permeability enhancement, saturation-dependent permeability, stress dependent stiffness and gradual degradation of oil sands due to dilatant shear deformation and strain localization. The results of the hydraulic fracturing simulation indicate that poroelasticity as well as shear fracturing can result in breakdown and propagation pressures larger than the maximum in-situ stress. Applying such pressures in fracturing operations can compromise the caprock integrity. It is found that at injection pressures below the vertical stress, saturation-dependent relative permeability and the development of shear fractures in the reservoir highly influence the injection response.
In 2012, the Reservoir Analysis Sonde (RAS) pulsed-neutron system was introduced by Hunter Well Science and Allied Wireline Services. Along with Sigma logging and carbon-oxygen (C/O) spectroscopy, the system features an array of three gamma-detectors (referenced as Near, Far and Long) for increased sensitivity to gas and porosity. One of the initial applications of this system was reservoir monitoring of a CO2 flood in the Permian Basin of west Texas.
The Goldsmith-Landreth (San Andres) field of Ector County, Texas was initially discovered in the 1930’s. After initial production, the field went through years of water-flooding and by the mid 1980’s the reservoir was at residual oil saturation. In 2009, Legado Resources began a pilot study on recovering the residual oil by CO2 flooding. In contrast to gravity-drained miscible flooding, the pilot used a more active flooding in addition to water-flooding to produce the residual oil. This flood also targeted the residual oil below the ancient oil-water contact. The RAS system was used for monitoring CO2 position and movement, as well as defining the base of the residual oil. This San Andres reservoir is a dolomite reservoir with porosities in the range 6 to 16 percent; the produced water is also the injection water and is in the range 40 Kppm to 50 Kppm sodium chlorides. A quick-look processing recipe was applied using the ratios of the Near and Long detectors to estimate porosity and gas-in-place. Sections of the reservoir with gas-in-place were assigned an ad hoc gas saturation based on literature for west Texas CO2 floods; the parameters of Sigma-based oil saturation and the porosity calculations were matched to core data.
In an effort to measure gas saturation more accurately, a follow-up project with detailed Monte Carlo models that included the specifics on reservoir rocks and fluids were built and processed. In the literature, (Odom 2001, Trcka 2006, Zett 2011) are discussions on using the multi-detector pulsed-neutron (MDPN) data to measure gas saturation independently using the long-spaced response. Given an independent measurement of the gas saturation, in reservoirs with saline formation water, the Sigma interpretation can be used for oil/water saturation. In contrast, previous literature on 3-phase monitoring of floods (Badruzzaman 1998, Harness 1998, Zalan 2004) describes using carbon-oxygen and sigma as the two inputs in a 3-phase fluid solution. These techniques were primarily focused on steam-floods with fresh water, thus sigma drove the gas (steam) saturation and C/O drove the oil saturation. The SIGMA-MDPN recipe is more robust than the SIGMA-C/O model and can be logged in a single logging pass, however, care must be exercised in diagnosing wellbore uncertainty. Several examples of the interpretation are presented, along with borehole diagnostics from the RAS and cement bond logs.
Solano, Nisael A. (University of Calgary) | Clarkson, Christopher R. (University of Calgary) | Krause, Federico (University of Calgary) | Lenormand, Roland (CYDAREX) | Barclay, Jim E. (ConocoPhillips) | Aguilera, Roberto (University of Calgary)
Estimation of rock properties from drill cuttings is proving valuable in the geologic description of tight gas strata. The characterization scheme includes an integrated analysis of detrital and authigenic mineralogy, pore geometry, and flow and storage capacity using drill cuttings samples calibrated with a limited amount of core data. This methodology has been successfully applied to characterize the fine-grained siliciclastic, shallow marine Nikanassin Formation in the Deep Basin of Alberta.
This workflow is particularly useful for the characterization of undercored low permeability hydrocarbon-bearing intervals from both new and legacy wells. Macroscopic description of drill cuttings samples, coupled with petrographic analysis performed on custom made multi-sample thin sections from the same samples allows a direct correlation between these two observations. The principal detrital and authigenic components are also investigated through microprobe analysis and SEM imaging of selected samples. Porosity values and dominant pore geometries are estimated using laboratory measurements and thin section image analysis. Finally, permeability values are measured using the Liquid Pressure Pulse methodology on drill cutting samples.
Porosity and permeability of the analyzed samples ranges between 2-13%, and 0.01-0.25 mD, respectively. Porosity values from drill cuttings samples are found to be slightly higher than routine core analysis measurements, which in turn usually have higher values than porosity estimated from thin sections. A high degree of reproducibility was confirmed for the porosity values obtained from the saturation method on drill cutting-sized samples, with resultant values comparing very well with measurements from standard nuclear magnetic resonance on the same samples. Reservoir quality within the analyzed samples is highly affected by quartz overgrowth and subsequent carbonate cement, with the former increasing with depth. Compared to the dominant microporosity domain, remnant intergranular porosity significantly enhances the permeability of the samples.
This workflow represents an inexpensive yet comprehensive interpretation tool specially targeted to improve the geological understanding of potential by-passed tight gas formations, which usually lack representative cored intervals. In addition, economic returns can be highly optimized by partial replacement of coring programs by appropriate sampling and preservation of drill cuttings samples in new wells.
Coal permeability is sensitive to the effective stress and is therefore coupled to the geomechanical behaviour of the seam during gas migration. The geomechanical response of the seam is complicated by the additional effect of coal shrinkage with gas drainage. Existing coal permeability models, such as those proposed by Shi and Durucan (2004) and Palmer and Mansoori (1996), simplify the geomechanical processes by assuming uniaxial strain and constant vertical stress. Connell (2009) and Connell and Detournay (2009) investigated these assumptions using a fully coupled simulator. An important obstacle to the use of the coal permeability models of Shi-Durucan or Palmer-Mansoori is the characterisation of the various physical properties involved, since a number of difficult to measure properties are involved. This paper summarises the influences on coal permeability and in particular the role of coal shrinkage with gas desorption and compressibility with pore pressure and the importance these processes could have on predictions of gas production. The paper considers the assumptions involved in the derivation of the models to describe coal permeability and the impact these could have on predicting gas production. A novel model is derived which is more general and this serves as a basis for the discussion presented in this paper. Measurements of coal properties (cleat compressibility, geomechanical properties, Biot coefficient) with respect to pressure are presented for two Australian coals (a sample from the Hunter Valley and one from the Bowen basin) and the measured behaviour compared with that assumed in the Shi-Durucan and Palmer-Mansoori coal permeability models derivation.
As with many reservoirs permeability usually plays a central role in determining coal seam methane production. Coals are viewed as naturally fractured reservoirs with a matrix that is often assumed to have a negligible permeability in comparison to the fracture system. These fractures in coal are known as cleats with the cleat aperture sensitive to the effective stress; increased effective stress acting to decrease the cleat aperture and thus permeability. Gas in coal is largely stored by adsorption which introduces another complication in the understanding of coal permeability behaviour; as gas desorbs from coal the coal matrix shrinks, with gas adsorption the matrix swells (in this paper this shrinkage or swelling will be referred to as sorption strain). Thus there are two competing effects on coal permeability; lowering the pore pressure (such as during primary production) acts to increase the effective stress and thus reduce the permeability due to cleat compression. However the drawdown also results in desorption of methane leading to matrix shrinkage and increased coal cleat apertures and thus permeability. Conversely, raising the pore pressure and gas content (such as during CO2 storage to enhance coal bed methane recovery) will reverse this process by raising the pore pressure and increasing the gas content leading to coal matrix swelling.
Gray (1987) presented a coal permeability model which represents the effects of the matrix shrinkage and pore pressure changes on coal permeability. Various other models have been presented, including Harpalani and Zhao (1989), Sawyer et al. (1990), Seidel et al. (1992), Siedel and Huitt (1995), Palmer and Mansoori (1998), Shi and Durucan (2004, 2005), and Palmer (2009), etc., where both the shrinkage and pore pressure effects are included. Among these models, the Palmer-Mansoori model (Palmer and Mansoori, 1998) and the Shi-Durucan model (Shi and Durucan, 2004) are two popular choices used in reservoir simulation of gas migration.
The LaRonde orebody is a world-class Au-Ag-Cu-Zn massive sulphide lenses complex with reserves extending from surface down to 3110 meters and still open at depth. Production is ongoing from 980 meters to 2360 meters below surface through the 2240 meter deep Penna Shaft, which is the deepest single lift shaft in the western hemisphere. Due to the large vertical dimension of the orebody, mining operations intersect a wide variety of environments. As the stress to strength ratio of the rock rises, the behavior of the rock mass changes drastically, from hard and brittle, to soft and squeezing. As a result, rock mechanics and ground control practices have evolved considerably as mining activities progressed deeper and the limits of conventional support systems were reached. This paper focuses on observed field behavior of support systems in the wide range of ground conditions found at LaRonde. In particular, this paper addresses the limitations of current support systems and provides preliminary results of a new ¡°hybrid bolt¡± that can overcome most of the limitations of current systems.
Located near the village of Preissac in Northern Quebec, the LaRonde mine has been in operation since 1988. Over 600 employees are operating the complex, for an average production of 7250 tonnes per day. The 2240 meters deep Penna Shaft is used to hoist the ore. Production is ongoing between level 98 (980 meters below surface) and level 236 (2360 meters below surface), from 4 distinct mining horizons. Figure 1 presents a longitudinal view of the LaRonde orebody. As of 2005, reserves at LaRonde totaled over 17 million tonnes of ore, for over 1.6 million ounces of gold (www.agnico-eagle.com). The LaRonde orebody remains open at depth, with reserves as deep as 3110 meters below surface. Until late 2005, 215 was the lowest production level.