Shale Energy Engineering 2014: Technical Challenges, Environmental Issues, and Public Policy

Discharge of subsurface fluids (water, oil and gas) causes land subsidence and earth fissures. Numerical simulation of land movement due to groundwater withdrawal from an aquifer system has been conducted in this paper. A hyperbolic stress-strain relation has been introduced which leads to a stress-dependent specific storage coefficient and, further, to a nonlinear flow equation. Three secondary physical laws and a bulk flow relation have been invoked to develop a new module that is incorporated into the parent code MODFLOW. A conceptual model for an aquifer system with a well has been established. Three-dimensional land movement due to discharge has been simulated using both linear and nonlinear models. The results indicate that land movement using a linear model can likely be overestimated when compared to that using a nonlinear model. This conclusion is consistent with the stress-dependent specific storage coefficient derived in this paper. The numerical simulation demonstrates that a hyperbolic model may provide better prediction than an exponential model, another nonlinear model previously applied. Sensitivity analysis of parameters indicates that the hydraulic diffusivity plays a significant role in response to land movement while pumping.

Oil and gas industry leaders, stakeholders, and regulatory agencies understand the importance of protecting groundwater resources. Many oil and gas companies proactively engage in voluntary groundwater sampling, both prior to and after hydraulic fracturing (fracing) events, to document groundwater conditions, promote scientifically-based transparency, and ensure that public health is not impacted as a result of development operations. These baseline water quality (BWQ) programs have tremendous potential for promoting mutual understanding, collaboration, and "win-win" development of oil and gas resources. A BWQ program often involves sampling water sources before drilling commences and after the drilling and fracing process is complete. Water samples are analyzed for chemical constituents that occur naturally within aquifers, as well as constituents related to oil and gas activities. Techniques for analyzing total petroleum hydrocarbons (TPH) can determine if low level TPH detections are related to oil and gas activity or if the detections are due to naturally occurring carbon sources. If methane is present in the water samples, methane isotopic analysis may be performed to determine the provenance of the gas. Statistical analyses can be utilized to further interpret the results of the BWQ and draw conclusions with regard to overall significance.

Recent estimates predict over 20,000 wells will be drilled for hydraulic fracturing in the Eagle Ford Shale over the next 15 years, accounting for approximately 5-7% of the total water use within the main 16-county area, and as high as 89% in one rural county. Since each well requires about 10,000-25,000 m³ of water, there is significant concern about fresh water consumption in drought-stricken South Texas. Hence, development of the Eagle Ford Shale will require water management strategies that maximize use of non-potable water. The main objective of this study is to evaluate the feasibility of using reject concentrate streams from groundwater RO desalination plants located within the Eagle Ford Shale region as hydraulic fracturing fluid. This could have two synergistic advantages: (1) elimination of brackish desalination concentrate discharges to surface waters, and (2) provision of a source of water for the oil and gas industry that does not consume freshwater supplies. This study will perform comprehensive chemical characterization of both an RO reject concentrate stream and hydraulic fracturing flowback water. It will also perform a geochemical modeling analysis to assess the down-hole scaling potential associated with the RO concentrate if used as hydraulic fracturing fluid in the Eagle Ford.

Best water management practices (BMPs) and water treatment technologies in unconventional oil and gas development operations have been evolving since the late 1990s. That evolution underwent two major accelerations.The first started around 1999, when coal bed natural gas water production was climbing and disposal options in several western states were limited. The second acceleration started in 2005 with the growing adoption of high-volume hydraulic fracturing (HVHF). Well drilling, completions and production operations of modern horizontal drilled unconventional plays require large volumes of water during the well lifecycle. The lifecycle cost of water alone for a Marcellus Shale well can exceed $1 million (Shauk 2012). Economic and environmental concerns have provided impetus for a "paradigm shift" toward the development of pre-planned water management programs that cover the full lifecycle of a field. The goal of such programs is to minimize fresh water use, optimize environmental and safety effects, and reduce costs. This paper will focus on trends in water management programs, water treatment technologies, and water best management practices.

The process of hydraulic fracturing is a popular method for extracting oil and gas in Texas. It is estimated that approximately 4 to 8 million gallons of water are utilized per each well that is drilled and developed. The increase in hydraulic fracturing activity in Texas has led to an increase in the amount of water used by the oil and gas industry, from 44 million cubic meters (36,000 acre-feet) in 2008 to 100 million cubic meters (81,500 acre-feet) in 2011. The multi-year-long drought, increasing pressure to regulate water usage, and desire to achieve greater water conservation have pushed some policymakers in the State of Texas to consider mandating the recycling of produced and flowback water from drilling operations. This paper focuses on the statewide water needs in Texas, the story of the legislative mandate, and the implications of such mandate on future hydraulic fracturing operations across the country.

Produced water management is a major challenge to oil and natural gas exploration and production, in particular for unconventional gas development. Rapid development of shale gas production, regulations, water scarcity, concerns of environmental impacts, and limited disposal options are driving operators to consider, plan and change their current hydraulic fracturing and produced water management methods. Development of beneficial use of produced water has become a new trend for sustainable shale gas production. Treatment and beneficial use of flowback and produced water can enhance gas recovery and economic viability of gas production. It also minimizes potential environmental impacts, reduces demands on local water supplies, and meets regulatory requirements. However, there are many factors affecting the feasibility of beneficial reuse, including:water quality and quantity; appropriate treatment technologies, economics, disposal options and capacities; environmental impact; and regulations. This study evaluated the challenges and prospect of beneficial use through review of existing studies on flowback and produced water management in major shale plays. Currently, operators in Marcellus Shale are reusing over 90% of flowback and produced water, mainly for hydraulic fracturing. Barnett Shale, Eagle Ford Shale, Fayetteville Shale and Haynesville Shale are using deep well injection as their primary disposal method. However, produced water beneficial use potential in Barnett, Eagle Ford and Fayetteville is expected to be high due to new regulations and water shortage due to droughts.

Large-scale development of the Appalachian Basin shale gas resources began in 2008. Waste water, its characterization and handling have emerged as critical components in the industry's environmental management strategy. This study summarizes the literature on flowback characterization: organic, inorganic and radioactivity. We found that inorganic constituents were dominated by extremely high concentrations of Na, Cl, Ca, Mg, Br, Ba and Sr with total dissolved solids concentrations approaching 200,000 mg/L. While many organic compounds were found at high concentrations, only benzene was consistently found in excess of its drinking water standard (MCL 5 μg/L). Normally occurring radioactive materials (NORMs) were also examined and α, β, ²²⁶Ra and ²²⁸Ra were consistently found above their primary drinking water MCLs in flowback water. Concentrations of all of these constituents increased during the flowback cycle and concentrations of nearly all measured parameters were much higher in flowback water than in the injected hydraulic fracturing fluids. This indicates that the bulk of measured constituents, including benzene, are acquired through fluid contact with the formation and not from the injected hydraulic fracturing fluid.

In the domain of shale gas extraction, water is used during the process of fracturing the shale in order to retrieve the gas trapped in the formation. A portion of the injected water- known as flow-back water - is recovered during the initial extraction of the gas. Electrodialysis - which has gained more attention in recent years - is an alternative for onsite treatment (or pre-treatment) and recycling of the flow-back water. The method is based on an electrically assisted membrane process for separation of salts from the water. Flow-back water has very high concentrations of dissolved solids (e.g. calcium, barium, magnesium, and iron). Electrodialysis is highly susceptible to these cations and has great potential to be used as a desalination process in such an aggressive environment. In this study, the efficiency of the electrodialysis as a desalination process for flow-back water was investigated using samples of flow-back from Marcellus shale wells in the laboratory scale. The preliminary findings in the experimental evaluation of the method indicated a removal of total dissolved solids of more than 90%.

By 2016, development of the Marcellus shale gas play in the Northeast will generate an estimated 227 million liters (60 million gallons) per day of hydrofracture flowback and production wastewater. This wastewater is close to saturation with sodium, calcium, magnesium, strontium, and barium chlorides as major constituents. Discharge of such wastewater into surface waters has been effectively outlawed in Pennsylvania, leaving deep well injection and treatment for recycle/reuse as current disposal options. Resource recovery via the processes of precipitation and fractional crystallization - which produces salable products from wastewater - has been developed as an economic, environmentally superior, disposal method for Marcellus wastewaters.

The recent boom in unconventional natural gas (UNG) production from the Marcellus Shale Formation in Pennsylvania has brought challenges of how to treat the large volumes of wastewater produced during drilling and hydraulic fracturing. In the late 2000s, capacity at permitted wastewater treatment facilities was quickly overwhelmed. Drilling companies began sending their wastewater to Publicly Owned Treatment Works (POTW) that were not designed or permitted to treat wastewater high in Total Dissolved Solids (TDS) and chloride. Recognizing the need for wastewater effluent standards that specifically targeted TDS and chloride, the Pennsylvania Department of Environmental Protection (DEP) added new effluent standards under 25 Pa. Code § 95 in August 2010. The new effluent limits for TDS and chloride were set at 500 mg/L and 250 mg/L, respectively. Under 25 Pa. Code § 95, facilities permitted to treat oil and gas wastewater prior to August 2010 were exempt from the new effluent limits. Although much progress has been made in reducing TDS and chloride loads from UNG wastewater through regulation and voluntary agreements, the exemption in 25 Pa. Code § 95 still exists for conventional oil and gas drilling wastewater, allowing the continued discharge of TDS and chloride at hundreds of times greater than the new limits. An overview of Chapter 95 is provided along with two case studies of wastewater treatment facilities that highlight the regulatory successes and failures in reducing TDS and chloride discharges to Pennsylvania's rivers.

Produced water from development of oil and gas resources - especially development of unconventional resources using hydraulic fracturing - requires management to avoid unintended environmental impacts. The recent rapid expansion of development in Pennsylvania's Marcellus Shale formation has led to significantly higher volumes of produced water requiring management. Conventional produced water management frequently involves treatment at centralized brine treatment plants that provide partial treatment and release into surface waters through NPDES permits that are exempt from salt limits, although use of this treatment option has declined from 3.18 to 2.27 Mbbls from 2006 to 2012. Reuse of conventional produced water increased significantly in 2012 (to 43% of the total volume). Although representing a small fraction of total water under management (less than 10%), use of surface-discharging publically owned treatment plants that do not remove salt has increased for conventional produced water (from 0.35 Mbbls in 2006 to 0.77 Mbbls in 2012). Unconventional (shale gas) produced water is predominately managed through recycling and reuse. Use of surface-discharging plants significantly declined between 2006 and 2012 (from 5.81 Mbbls to 0.62 Mbbls), while underground injection and treatment at facilities that return treated water for reuse have both increased.

The purpose of this research is to characterize residual solids from hydraulic fracturing in the Marcellus Shale to predict leaching behavior in the natural environment for elements of concern. Solid samples were subjected to strong acid digestion to determine:(1) the total environmentally available concentration of elements and to weak acid digestions with various extraction fluids (reagent water, inorganic acid, organic acid, and synthetic municipal landfill leachate) , and (2) worst-case leaching potential in various disposal environments. Comparing these results, it is possible to determine the effect of extraction fluid and sample characteristics on the leaching potential of select elements. This may be further developed to determine best management practices for the disposal of hydraulic fracturing residual solids.

Engineers and geologists within the Appalachian Basin (encompassing the Utica and Marcellus formations) focus on the location and composition of shale layers located thousands of feet below the Earth's surface. However, the soil and rock encountered within the top 30 meters (100 ft) can have a direct impact on the ability of the resources to be developed. A properly designed geotechnical investigation - consisting of site reconnaissance, geophysics and/or geotechnical drilling - can assist in identification of and anticipatory design for geohazards from the construction phase through a lifetime of well pads, water impoundments, midstream transmission systems, or access roads. This paper presents three case studies of geotechnical investigations for midstream operations that were performed during the preliminary design phase of the projects. Case Study #1 consists of a geophysical investigation performed on sensitive federal land in conjunction with geotechnical drilling operations in order to identify the appropriate geometry for a horizontal directional drill (HDD) installation of a 0.61-m (2-ft) diameter pipeline. Case Study #2 discusses a geotechnical drilling investigation and foundation design performed for the construction of a natural gas transmission facility. Case Study #3 presents the geotechnical drilling investigation for the design of a structure to support a natural gas transmission line/state route crossing located in an area that is to be subjected to longwall mining in the near future.

Hydrocarbon production from unconventional shale gas reservoirs has become more common in recent years. Characterization of organic-rich shale formations is an important task because deformational properties not only control the success of the hydraulic fracturing process, but also how transport properties are changed during production. A common problem encountered by the industry is that these deformational properties cannot be captured by geophysical techniques, which can only measure elastic properties. Therefore, it is very important to understand how deformational properties are related to elastic properties. In particular, the relationship between ductile deformation and elastic properties, and relations between elastic stiffnesses and clay/organic content of the shale formation are of significant importance. In order to investigate these relationships, laboratory experiments were conducted on shale gas samples taken from a Marcellus outcrop at State Game Lands 252, located in Lycoming and Union counties, Allenwood, Pennsylvania. Laboratory results show that the nonlinear nature of these rocks makes the characterization challenging. Appreciable differences were found between dynamic and static properties measured under the same stress conditions and directions.

This paper outlines the basic idea of a macroscopic model on the dynamic comminution or fragmentation of rocks, concrete, metals, and ceramics. The essential idea is that the driving force of comminution under high-rate shear and compression with shear is the release of the local kinetic energy of shear strain rate. The density of this energy at strain rates >1,000/s is found to exceed the maximum possible strain energy density by orders of magnitude, making the strain energy irrelevant. It is shown that particle size is proportional to the -2/3 power of the shear strain rate and the 2/3 power of the interface fracture energy or interface shear stress, and that the comminution process is macroscopically equivalent to an apparent shear viscosity that is proportional (at constant interface friction) to the -1/3 power of this rate. A dimensionless indicator of the comminution intensity is formulated. The theory was inspired by noting that the local kinetic energy of shear strain rate plays a role analogous to the local kinetic energy of eddies in turbulent flow.

This paper presents the results of a numerical study where guided ultrasonic waves (GUWs) are used for the structural health monitoring of pipes. The method hypothesizes the generation and detection of longitudinal, torsional, and flexural waves from each transducer of two annular arrays located inside the pipe. The signals are processed using continuous wavelet transform and Hilbert transform to extract two damage-sensitive features. The estimation of the features for healthy condition is formulated in terms of an optimization problem based on the imperialist competitive algorithm. Finally, a probabilistic approach is used to create an image of the pipe in search for possible structural anomalies. A commercial finite element code is utilized to model the presence of eight ultrasonic transducers in contact with the interior wall of a pipe. Each transducer acts either as actuator or as a sensor. The time waveforms associated with all possible actuator-sensor pairs are processed using the algorithms proposed here. The results indicate promise and future studies should focus on the experimental validation of the methodology.

Shale gas is becoming an increasingly important energy source worldwide. The geomechanical properties of shale rocks can have a major impact on the efficiency of shale gas exploration. This paper studies the mineralogical and mechanical characteristics of a typical gas shale in Ohio, USA. A scanning electron microscope (SEM) with Energy Dispersive X-ray (EDX) analyses was employed to measure the microstructure and material composition of the shale rock. The anisotropic behaviors of shale rock, including compressive and tensile strength, were experimentally measured. The effects of anisotropy on the observed strength behaviors and failure patterns were discussed. The characteristics of shale rock are also studied by non-destructive wave speed measurements. The shale demonstrated strong anisotropic behaviors with the tensile strength perpendicular to the bedding plane around 300-360 times of that parallel to the bedding plane. Results of ultrasonic testing indicated that both compression and shear wave velocities show strong anisotropic patterns. The compression wave speed was smallest in the direction perpendicular to the bedding plane, while the shear wave speed was smallest in the direction parallel to the bedding plane. The ratio of wave speed anisotropy is around 1.3-1.4 times for compression wave. The ratio of wave speed anisotropy is more diverse for shear wave.

This paper reviews some of the major scientific challenges faced in the field of non-conventional energy production. Particular attention is given to shale rocks, in which the production of hydrocarbons involves hydraulic fracturing, fracture connectivity, multiphase flow, and reactive-transport. In regard to these problems, the paper describes a series of analytical and computational models to study fracturing in quasi-brittle solids and captures failure events in multi-phase geomaterials subjected to simultaneous changes in stress state, fluid pressure, moisture content, thermal and chemical conditions. Advantages and limitations of the different techniques are discussed, setting a vision for a new generation of multi-scale/multi-physical models for shale that can be used to support the optimization of the extraction processes, as well as to address industrial needs and mitigate the risks of environmental hazards, groundwater contamination and induced seismicity.

The author invented a prototype 2-D discrete element program to simulate granular particle structure in different packing environments of sedimentary rocks. All particle shapes are assumed to be square to realize angular coarse particle depositions and limit simulation process time. However, this angular particle shape can enhance developments of potential internal microcracks/discontinuity or hidden pore structures inherited from the grain size difference. Stagnant packing mode simulated a lake or low tide sea environment where granular particles settled under a stagnant water condition and only allowed vertical movement. The packing was performed one dimensionally with no lateral agitation allowed. Reciprocal packing mode simulated severe tidal action during particle sedimentation in a marine valley environment with alternative deposition orientations/sequences. Densely packing mode simulated a pore structure to produce the maximum unit weight for discrete particle group different in size and number. Oversized void or discontinuity was not generated in this mode to produce the minimum porosity of sedimentary rocks. Based on simulation results, well-graded or poorly-sorted discrete particles produced more various pore size distribution and more extensive microcrack generation in both stagnant and dynamic settlement modes. The program is able to count the individual pore/crack numbers and sizes after the packing simulation. Although the program did not handle self-healing or re-closure of unrealistic large cracks or discontinuity which would not take place inthenatural environment, simulation outputs of microcrack and discontinuity orientation still can help understand the tendency of anisotropic fracture development associated with fracking/well stimulation for shale gas/oil production.

The horizontal portion of the borehole used to extract gas from shale deposits is made of an annulus of cement and a metal casing. This annulus has a series of diametrically opposed cracks made by a perforating gun. The annulus with the cracks is subjected to a fluid pressure or hydrofracturing. Little is known about the influence of the number, depth, and separation of the cracks on the fluid pressure efficiency in cracking the shale. The main objective of this study is to use fracture mechanics theory to evaluate the effect of the number, separation and depth of the gun-induced cracks on the hydrofracturing of the shale. The level of tensile stress induced by the hydrofracturing fluid is a function of the Mode I stress intensity factor K_I. This study indicated that K_I was the highest for the case of two single diametrically opposed vertical cracks. K_I was found to decrease in value as the number of diametrically opposed cracks increased in number and decreased in separation. Also, regardless of the number of the gun-induced cracks, the K_I value generally increased in value as the depth of these cracks increased in value.

The technique of multistage hydraulic fracturing from horizontal wells is universally credited with enabling the economical production of hydrocarbon resources from shale formations. The method almost always entails the injection of fluid through the wellbore with the potential to create hydraulic fractures from multiple reservoir entry points, typically clusters of wellbore perforations, that are spaced out along the wellbore within a section that is colloquially referred to as a "stage". Arguably the most basic question about this situation is how many perforation clusters within a given fracturing stage can be expected to produce growing hydraulic fractures. This paper presents a numerical investigation of this issue that employs a newly-developed, fully-coupled, parallel, planar, 3D hydraulic fracturing simulator that features: implicit time stepping, an implicit level set scheme to locate the propagating hydraulic fracture fronts that respond to their regimes of propagation and enables highly accurate simulations using a very coarse mesh, and the capability to dynamically partition the fluid among multiple, simultaneously growing hydraulic fractures in parallel, overlapping planes. Our results demonstrate the dependence of the energetically preferred number of growing hydraulic fractures on the length of the isolated zone, the height of the reservoir, and the relative importance of the fluid viscosity. In particular, we show that reservoirs with effective height containment and injection strategies that ensure substantial viscous dissipation will promote growth of multiple simultaneous hydraulic fractures rather than localization to just one or two dominant fractures.

This paper studies the conditions of crack propagation in a subcritically stressed rock subject to chemically aggressive environment, which is often encountered in technologies of oil/gas extraction from low-permeability reservoirs. Frequently, matrix acidizing is employed, upon which mineral mass is dissolved and washed away by fracturing fluids. Such a mineral mass removal weakens the material mechanically and causes crack propagation and, eventually, permeability changes in the medium. The crack process zone is modeled mathematically using a recently developed chemo-plasticity coupling model. The coupling is established between mineral dissolution and a yield limit of rock matrix via chemo-plastic softening function. The rate of dissolution is a function of a rate constant and variable internal specific surface area which is, in turn, affected by the initial void ratio as well as dilatant micro-cracking induced by irreversible damage (treated as a plastic strain). Numerical simulations for such a coupled system are performed under simplified boundary conditions.

Numerical simulations were performed for the expansion of expandable casing with a threaded connection. Specific concerns that were focused on include evaluating the contact between the pin thread and the box thread, as well as predicting the driving force applied to the mandrel cone. The results indicate: (1) with a specific value for the axial velocity of the mandrel cone, the connection surfaces between the pin thread and box thread maintain good contact in most areas after expansion; (2) during most of the expansion process, the values of the driving force applied to the mandrel cone are less that 1×10⁶N. However, the maximum value can be as high as 2.03×10⁶N; (3) the contact status between the pin thread and the box thread can be estimated with reasonable accuracy using coarse mesh. However, finer mesh can more accurately identify the localized peak value of the contact stress and that of the equivalent plastic strain at the root of the pin thread. This can also result in a higher driving force applied to the mandrel cone because of the plastic hardening property; and, (4) the rate of axial compaction after radial expansion is 1.45%.

This paper describes a hydro-mechanical coupled model for hydraulic fractures using the eXtended Finite Element Method (XFEM). To analyze the non-linear coupling behavior of hydraulic fractures, the XFEM uses local enrichment functions within a regular finite element framework. Thus, the mechanical behavior of a domain with fractures can be efficiently estimated by the method without explicitly meshing the discontinuities, as would be necessary in other numerical techniques. The governing equations and coupling algorithms are presented as well as the required assumptions for hydraulic fractures. The 2D coupled XFEM program is validated by a numerical example study and shows coupled flows and their influence on stresses and fracture deformations.

Fluid flow regime strongly affects fracture formation and growth in shale formations. The interaction between solid and fluid parts in a predefined discontinuity should be considered. Moreover, the fluid regime should be accurately monitored in every solution step. This study uses Isogeometric analysis (IGA), a recently developed numerical method, for modeling 1D fluid flow in shale medium. Splines, the functions commonly used in Computer-Aided design (CAD), are employed to model the geometry as well as to approximate solution results. Consequently, IGA eliminates the need for computationally-expensive remeshing, which is a time-consuming step in the finite element method. A benchmark problem was simulated using the proposed method, and the results showed that IGA is a robust tool to model fluid flow in shale.

The development of novel technologies, such as Enhanced Geothermal Systems (EGS), has been decelerated due to induced seismicity. Sophisticated traffic light systems, which assess the seismic hazard in time for taking precautionary measures, can assist in the successful development of EGS sites close to urban areas. We present here the modeling approach for a hybrid model that can be used in such a traffic light system. This hybrid model combines the HFR-Sim software with stochastic models that have been used for forecasting induced seismicity. HFR-Sim is an EGS simulator that can model flow inside dynamically changing fracture networks. It offers discrete representation of fractures and can be used for simulating a wide range of three-dimensional problems which are related to the design, creation and operation of an EGS reservoir. Here, the coupling of HFR-Sim with a stochastic seed model is explained. Exemplary simulations are performed with the resulting software and the results obtained by those simulations are discussed.

Disposal of flow-back and produced waters in deep injection wells is known to induce earthquakes in a small number of cases. While many of these induced earthquakes are small (less than moment magnitude [M_W] 5), some are in the MW 5 to 6 range and, potentially, can be a significant contributor to seismic hazard at a nearby site. Assessing seismic hazard from disposal-induced earthquakes is complicated by uncertainties in the characteristics of the events. Probabilistic seismic hazard analysis (PSHA) provides a way to incorporate these uncertainties. As a first step, this paper identifies some issues in characterizing disposal-induced seismicity for PSHA and discusses approaches that may be used to address them. Issues discussed are characterization of the rate of recurrence, maximum magnitude, ground motion prediction, and focal depth.

Microseismic events in shale-gas hydraulic fracturing are due to propagation of induced fractures. Larger and noticeable seismic events are less likely to occur, but the probability of occurrence will increase in the presence of a pre-stressed fault. Intersection of an undetected and pre-existing fault/fracture with the production well is the main cause for upward extension of induced fractures. This upward extension of fractures may lead to reactivation of existing faults and can increase the induced seismicity potential. This study investigates the induced seismicity and fault reactivation potential associated with hydraulic fracturing operations when a limited-dimension fault exists close to the fracturing site. For this purpose, a 2D, fully coupled, hydro-mechanical, numerical model was developed to simulate changes in the stress distribution in the fractured zone and fault. The results obtained from the numerical simulations were used to determine the fault responses. Seismological theories were adopted along with the fault slips obtained from the numerical simulations to estimate the magnitude of induced seismic events. Parametric study was performed to investigate the impact of injection rate and fault permeability on the magnitude of an induced seismic event. In all cases which were examined, the magnitude of induced earthquake was very low and never reached to the level of a noticeable seismic event.

Pipeline construction can be disruptive for rural communities in the vicinity of shale energy development and expensive for the pipeline companies, particularly if unanticipated blasting for excavating shallow pipeline trenches causes construction delays. A rock excavation index can be defined based on subsurface conditions interpreted from digital topography, geology, and soils data. Topographic data provide slope steepness and down-slope direction needed for evaluating sidehill conditions. Rock factors ranging from 0 for uncemented soil to 3 for nearby rock outcrop, weathered rock near top of ditch, or unweathered rock at any ditch depth can be created with GIS utilities as "rock factor" polygons along the pipeline centerline. Ground-condition variability requires subjective assessment and can be addressed in a limited way with use of seismic refraction surveys at truly random locations along the pipeline or at selected locations based on rock excavation factors. Rock excavation can be estimated using length-based and area-based percentages for ditch rock and right-of-way grading rock. Blasting details from actual construction records are needed to improve the accuracy of rock excavation estimation.

The concept of pure damage or the nucleation and evolution of voids is the primary phenomenon responsible for rock failure. However, the behavior of rocks under HPHT is very different than under the conditions of normal pressure and normal temperature. HPHT conditions occur at depths of around 3,000 m or below. A rock, which is otherwise a brittle material, behaves more like a metal showing ductile behavior under HPHT conditions. Due to confinement, the fragments can stay together and flow like a continuum, thus demonstrating ductile behavior. In this study, a ductile damage model was developed to examine the behavior of rocks under these special conditions. The model includes two coupled theories:(1) the elasto-plasticity theory and (2) the damage evolution theory. Two main problems that were studied are the un-constrained uniaxial compression and the completely constrained uniaxial problem. The results focus on the effect of confining pressure on rock failure.

Weak shale formations in oil shale production are the primary cause of instability in drill holes due to sloughing and swelling. During and after the drilling, shales continuously absorb water and consequently deteriorate with time. The effect of the deterioration results in the transformation of a hard rock with high cohesion and frictional resistance to a soft, fine-grained mass without cohesion, lower shear strength, and high swelling susceptibility. As a result, the shales swell and slough into the hole. Shales are primarily composed of varying amounts of clay minerals (i.e. chlorite, mixed layer illite-smectite, illite, and kaolinte), quartz, and other minerals such as carbonates, pyrite or iron oxides. In particular, understanding the influence of clay minerals on the shale is crucial to understanding the mechanical behavior of shales. This is because clays are highly reactive minerals in the presence of water. Due to this reactivity, shales tend to be highly susceptible to deterioration. This paper investigates the association between shale mineralogy and mechanical characteristics. For this study, shale samples were collected from a variety of locations in Kentucky. The specimens were assumed to be representative of hard and soft shales with high, medium, and low durability. These samples were crushed and laboratory testing was performed. The lab tests included index tests, mineralogical tests, and durability tests. It was observed from the results of this study that the mineralogy explained the activity and variations in several index properties, as well as the durability of the samples.

The importance of measuring in-situ stresses as an essential input factor to caprock integrity analysis is realized for both the technical management of SAGD and CCS projects (design of optimal operating pressure) and environmental reasons (loss of caprock containment). A common technique to carry out stress tests in impermeable and weak rocks, like clay shale, is to combine sleeve fracturing with micro-hydraulic fracturing test for which premature initiation of the fracture at the packer level can be avoided. Following a brief introduction of the micro-hydraulic fracture technique, field data obtained from a micro-hydraulic fracturing test program completed to assess the far field in-situ stress state for a proposed low pressure Steam-Assisted Gravity Drainage (LP-SAGD) pilot project located southeast of Fort McMurray, Alberta, Canada has been analyzed. Pressure analyses during and after micro-hydraulic fracturing are used to compute the minimum in situ stress at depth and illustrate the wide variability in the results. Issues surrounding stress alterations in the near wellbore region, low permeability and low injection volumes are shown to contribute to incorrect estimates of the far field minimum in situ stress.

This paper describes a group of field testing to study the characteristics of shale rock that shows strong anisotropic behaviors. Field borehole geophysical testing was performed at three locations to depths up to 280 ft. Based on the site investigation program, most subsurface rock consists of shale with thin clay seams embedded at certain depths. Borehole geophysical testing performed at the site included: (1)bBorehole caliper; (2) natural gamma and electrical resistivity; and, (3) acoustic televiewer. The purpose was to characterize the geological structures, especially the major joint planes in rock formation. Borehole seismic testing includes seismic downhole testing, which determined the shear wave velocity of rock at different depths, typically at 5-ft intervals. A specially designed seismic cross hole testing was conducted where the shear wave excitation was generated by striking the steel tube. Simplifications are made to interpret the crosshole signals where the rock is assumed to be consistent of a uniform heterogeneous material. The results indicate that the shear wave velocity in the inclined direction is typically much larger than the shear wave velocity in the vertical direction. The speed typically decreases as the inclination angle increases. This is consistent with commonly observed anisotropic behaviors in sedimentary rocks with horizontal bedding plan.

Injection pressure is a key factor in the design of a successful formation stimulation treatment of shale gas — the higher the pressure, the larger the stimulated volume. However, if the pressure is too high, the risk of compromising casing integrity during the injection process is also high. This paper analyzes a practical case of casing integrity problem resulting from injection in a field in southwest China. The purpose is to investigate the relative importance of the factors that influence casing integrity in a horizontal well section and to determine the upper bound of the safe injection pressure. Calculations were performed by using porous elastoplastic model with the finite element method. Anisotropy caused by non-uniform distribution of natural fractures is also included. For the specific casing and formation environment, it was found that casing integrity mainly depends on these three parameters:(1) injection pressure; (2) casing strength; and (3) cement quality. The maximum inward displacement of casing can reach 16 mm and result in serious ovalization under 90 MPa injection pressure, given non-uniform distribution of natural fractures and poor cementing quality. However, plastic deformation disappears with 80 MPa injection pressure when all other factors remain unchanged. Consequently, the upper bound of safe injection pressure is set as 80 MPa.

The FracFocus chemical disclosure registry provides public disclosure of hydraulic fracturing chemical additives used in nearly 55,000 wells by over 600 companies. ALL Consulting developed and manages the FracFocus database and web site. This database represents a treasure trove of information on the use of hydraulic fracturing fluids. This paper will analyze the disclosures in the FracFocus chemical disclosure registry database to give insight into the additives that are used in hydraulic fracturing in the United States. The large number of well sites that have been entered into the registry presents a rich population of hydraulic fracturing jobs over a wide geographic area and spanning a period of more than two years. From this database, it is possible to look at the breadth of chemicals used, their uses and variations in how they are listed, how the number and mixes of additives vary by service company and/or operator, and how geology/geography affects the composition and volumes of hydraulic fracturing fluids. The paper will also present time trends over the period in which FracFocus has been active.

This topic will cover erosion and sediment control for natural gas well pads, facilities, and pipelines. Proper erosion and sedimentation control design and implementation is a critical part of the development process for operators in the Appalachian Basin. The Clean Water Act (CWA) was enacted in 1972, and Section 402 of the Act established the National Pollutant Discharge Elimination System (NPDES). Oil and natural gas projects became exempt from NPDES permits through the Energy Policy Act of 2005, which was published as a final rule by the Environmental Protection Agency (EPA) on June 12, 2006. However, many states are beginning to implement their own requirements for these activities despite the federal exemption. For example, Pennsylvania has an oil and gas specific Erosion, Sediment, and Stormwater General Permit (ESCGP-2) that adopted many of the NPDES regulations. WV requires an Erosion and Sediment Control Plan be submitted with the well drilling permit package for review and approval. At this time, Ohio does not have a specific earth disturbance permit for natural gas projects. Typical erosion controls used on natural gas projects include rolled erosion control blankets, sprayed hydromulch, water bars, proper stream and wetland crossing methods, and temporary vegetation. Typical sediment controls used on a natural gas well pad or other permanent facilities can include diversion channels, sediment traps, sediment basins, compost filter sock sediment trap, compost filter sock, silt fence, and rock construction entrance. Typical sediment controls used on a natural gas pipeline project can include compost filter sock, silt fence, and rock construction entrances. This paper includes example projects and photographs of the controls used.

The Ninth Circuit Court of Appeals' opinion effectively exempted oil and gas operations from the National Pollutant Discharge Elimination System (NPDES) permit requirements for construction activities unless there is a discharge of a reportable quantity of oil or hazardous substance or a violation of a water quality standards. As a result, many oil and gas operations (including unconventional drilling operations for shale oil and gas development) are largely unregulated in terms of stormwater runoff despite construction of large well pads (approximately 1 to 5 acres) and miles of unpaved roads that have the potential to significantly impact surface water quality. This paper focuses on a broad review of literature regarding stormwater permitting of the oil and gas industry on a state-by-state basis. This paper also provides an overview of studies conducted that have examined the potential impacts that oil and gas development has on surface water quality.

The Mandatory Greenhouse Gas Reporting Rule (GHG Rule), 40 CFR 98 Subpart W - Petroleum and Natural Gas Systems, affects eight segments of the petroleum and natural gas industry. Starting in 2011, operators in the oil and gas production segment were required to: (1) correlate well locations with corresponding oil and gas fields for tracking and reporting purposes; (2) delineate well locations within facilities, basins, and fields; and, (3) aggregate greenhouse gas (GHG) emissions to determine applicability. Strategies had to be developed for recording data, estimating emissions, and reporting. Data was collected on production rates, equipment counts, well venting durations, gas compositions, and other parameters needed to estimate emissions. If producers could not fully comply with Subpart W requirements, the Environmental Protection Agency (EPA) allowed for use of best available monitoring methods, providing unique or unusual circumstances could be justified. Producers subject to Subpart W first had to report annual GHG emissions in September of 2012. Many shale oil and gas producers were not prepared to cope with the GHG Rule and many still may not be in full compliance. The authors discuss the requirements, challenges, and potential future implications of GHG monitoring and reporting for oil and gas producers.

This study focuses on pollutant stabilisation by the formation of less mobile, less toxic and less bio-available contaminant binding forms which protects humans, health and the environment. This treatment involves mixing a binding agent into the contaminated media by immobilizing hazardous constituents within the treated material. Cementitious materials such as CEM I, ground granulated blast furnace slag (GGBS), and bentonite are the predominant material choices because of their low associated processing costs, compatibility with a wide variety of disposal scenarios, and the ability to meet stringent processing and performance requirement. The aim requires selection of immobilising agents based on: (1) a set of physico-chemical tests designed to provide understanding of the processes involved in a particular stabilisation scheme; (2) durability of its products; and, (3) environmental impacts. Laboratory treatability studies are a fundamental part of the design process to assess mix, design and demonstrate that a binder can be selected to achieve remedial objectives for the design life of the remediation. The composition of the mixes was similar, but the difference is the percentage of water applied. A more comprehensive treatability study is proposed for ensuring that the study accurately reflects anticipated on-site conditions and the chosen binder satisfies the remedial objectives.

With the exploration of the Eagle Ford Shale drill sites, challenges come in disguise. The emission of Volatile organic compounds (VOC's) may have serious environmental and health impacts. A high level of exposure to VOC's can also happen in high traffic areas and cities having a larger percentage of older vehicles. This paper presents methods used for development of improved understanding of VOC sources and dispersion at hydraulic fracturing sites. A coherent infrastructure is needed to treat sensors and the generated data in an interoperable, platform-independent and uniform way. The composite ambient air total non-methane hydrocarbons (TNMH) levels can be effectively monitored. We also integrate a weather station to gather information on wind speed/direction at the fracturing site to build a correlation between the VOC and its dispersion in surrounding air. The ability to efficiently and effectively measure the concentrations of VOCs helps to better our understanding in reducing the VOC imprint and its adverse effect on individuals working at the drill site.

Fossil fuel power generation technologies offer a number of alternatives which involve different fuel supplies, production, power generation, and pollution control devices with varied environmental impacts. The holistic approach to examining these impacts through Life Cycle Assessment (LCA) can help decision-makers to quantify the many emissions trade-offs inherent in any change to the fuel supply and power production systems and ensure that a change in fuel or fuel sourcing does not result in increases of other environmental and health impacts. Besides endpoint emissions exiting from a smokestack in natural gas-fueled power generation, air toxics (such as formaldehyde, benzene and xylenes) are also generated through the supply chain from compressor engines and oil/condensate tanks, as well as intermittent sources such as well drilling and fracturing engines, well completions, gas processing, and also fugitive emissions from production and transmission. These emissions sources differ in quantity, species, spatially and in overall risk to the surrounding population. People exposed to air toxics at sufficient concentrations and durations may have an increased risk of developing cancer or experiencing other serious health effects. The purpose of this paper is to identify the appropriate air toxics emission factors for natural gas production and to utilize a LCA approach to quantify the "cradle-to-gate" air toxics emissions in terms of 1 kWh of electricity generated.

There is great concern on methane contamination in shallow groundwater aquifers as a result of drilling operations at unconventional natural gas reservoirs to produce natural gas. The presence of fractures in shallow groundwater aquifer is expected to accelerate the migration of methane in the aquifer. In this study, the time needed for methane to be detected at a monitoring well 500 m away from a leaking point in a shallow groundwater aquifer was determined. Both scenarios (with and without fractures) in the aquifer were studied with the use of a numerical simulation code (TOUGH 2) to determine the effect of fractures on methane migration. For CH₄ volume fraction detection, it would take 10.4 days to detect a significant CH₄ volume fraction increase at the monitoring well if the aquifer was homogeneous, while it would only take 2 hours to detect a significant CH₄ volume fraction increase at the monitoring well if the aquifer is a fractured aquifer.

Management of exploration and production (E&P) of industry waste and wastewaters has evolved rapidly over the last dozen years, driven by greater scrutiny of waste management practices by state and federal regulatory agencies, the public, and environmental groups. The evolution of waste management has accelerated with the focus on unconventional oil and gas plays and the use of multiple horizontal well completions from a single pad. The use of multi-well pads and the rapid development of regional areas have resulted in large, localized volumes of waste materials and water not seen before in the industry. This paper provides a comprehensive summary of the types of waste that may be generated during shale resource development and reviews regulatory requirements for waste management, recycling and disposal. It also discusses the importance of developing a "cradle to grave" waste management plan covering a project from exploration and development, through production of oil and gas, and eventually to site closure.

This paper presents an overview of the weights and types of solid and semi-solid wastes generated from exploration and production (E&P) of Marcellus Shale in the Commonwealth of Pennsylvania, and the engineering and operational issues faced by operators of municipal solid waste (MSW) landfills that co-mingle these wastes. Since approximately 2009, the volume of Marcellus Shale drilling (MSD) waste being landfilled has increased substantially, becoming a significant component of the waste stream and an important revenue source. Our understanding of the physical and strength characteristics of MSD waste is relatively limited, raising questions concerning the stability of the landfill waste mass that incorporates this waste stream. This paper includes results from several field and laboratory studies performed to evaluate and develop physical and shear strength properties of MSD waste. Conclusions from these studies are provided as well as the general guidelines for incorporating MSD waste into an MSW landfill.

Pipelines are routinely installed under streams and wetlands, resulting in temporary impacts to these resources. Section 404 of the Clean Water Act requires impacted streams, wetlands, and other waterbodies to be either restored or replaced. However, if the streams and wetlands are not restored correctly, the impacts can be permanent. The success of stream and wetland restoration is primarily dependent on returning the disturbed areas to pre-existing conditions and contours, which can be readily verified by monitoring construction activities or conducting post-construction monitoring. Recently, the U.S. Army Corps of Engineers (Corps) added a special permit condition to several linear projects in Pennsylvania requiring post-construction monitoring of restored streams and wetlands to ensure the success of the restoration efforts. The special permit condition required that a summary report of the monitoring be submitted to the Corps stating that excess fill material was removed and the site was restored to pre-existing conditions and contours. The report also needed to document the existence and relative success of revegetation efforts and installed erosion and sedimentation controls. The majority of stream and wetland permits for pipeline projects do not include a special condition requiring post-construction monitoring. Further, most natural gas operators do not typically conduct construction monitoring or post-construction monitoring to specifically review stream and wetland restoration efforts unless required as a permit condition. Without monitoring, easily avoidable and solvable problems could result in permanent stream and wetland impacts. As more pipelines are installed, stream and wetland restoration may become a primary environmental and regulatory concern and require more active construction monitoring by natural gas operators.

A boon in shale gas transmission infrastructure (SGTI) is underway due to the importance of shale gas as a critical global energy resource that can pave the way toward energy independence in the U.S. Because of its importance, it is critical to develop SGTI in responsible and sustainable ways by mitigating risks associated with geological hazards, while simultaneously evaluating potential environmental impacts resulting from SGTI development. We describe a robust set of quantitative and qualitative geomorphic methodologies that relying on state-of-the art data and methods for evaluating geological hazards related to SGTI development. The methods include:(1) high-resolution spatial and temporal monitoring of (potentially) active slopes in true three-dimensional (3D) space; (2) high-precision and accurate measurements of both modern and long-term erosion rates at the basin-scale; and, (3) the application of paleoflood hydrology for improving flood hazard evaluations.

Access roads connect a drilling pad for shale energy with public roads and are most often constructed with unbound aggregate surfacing materials. With traffic volume averaged over the lifetime of the road, an access road may be considered as a very low-volume road (ADT ≤ 400); however, a majority of the traffic occurs over 2-3 month spans during the initial construction and drilling phase of each shale oil and gas well on the pad. Research suggests that roads built and used in this manner have a great potential to produce and transport fine sediments to surface water bodies where increased sedimentation can be deleterious to the health of the ecosystem. Here, we present best management practices (BMPs) with consideration to traffic for shale energy development and for the design and use of access roads to minimize the production and transport of fine sediments. Emphasis is placed on adequate drainage features, quality maintenance practices, apposite materials, and proper traffic use.

Air permit application requirements and the resultant operating permit conditions for shale gas well pad production facilities differ from state to state. The lack of standardized permitting requirements and inconsistent permit conditions obliges applicants to evaluate and apply differing strategies from state to state to obtain approvals to install and operate the same equipment. Recent shale gas air permitting experiences in West Virginia and Ohio illustrate the different approaches between the Ohio Environmental Protection Agency and the West Virginia Department of Environmental Protection. The unique characteristics of gas production decline curves and their impacts on the potential-to-emit of proposed operations present unique challenges. Differences in permit application requirements and the resulting operating permits in Ohio and West Virginia are highlighted and discussed.

Exact wetland boundaries often are not easily identified. Natural gas producers and midstream operators often operate under deadlines and restrictions that are not compatible with regulatory timelines. As a result, they must rely on their consultants to make black and white decisions about project siting and routing when the science and regulations may not fully support such a call, leaving room for further discussion and potential judgment calls, or "grey areas". The outcome of similar situations can vary based on the geomorphic landscape, the environmental sensitivity of the general area, different regulatory agencies, and even differing opinions within the same regulatory agency. A comprehensive understanding of the 1987 U.S. Army Corps of Engineers (Corps) Wetlands Delineation Manual (Manual) and the Corps Regional Supplements - as well as state-specific water quality regulations - are required to make defensible decisions in the field so that projects can proceed ahead of regulatory concurrence. This requires thorough documentation of questionable areas to address project pressures while avoiding the inherent risks of differing opinions with regulators (who may not have the same history of the site as the consultant does) after costly design, construction schedules, or delivery contracts are in place. These decisions require frequent and open communication between the producer or midstream operator and the consultant.

The Eagle Ford Shale, a formation located in South Texas, is 80 kilometers wide by 640 kilometers long. It was traditionally considered to be economically unfeasible as a potential natural gas- and oil-producing formation. Since the onset of hydraulic fracturing of the non-porous rock, the Shale has rapidly become one of the highest producing areas of natural gas and oil, with a positive economic impact on the communities located over it. Previous studies have shown both direct and indirect impacts of the Shale development on the regional communities. The intent of this study is to re-evaluate the overall impact of the Eagle Ford Shale development in consideration of a set of extended components, in addition to the production, drilling, and related activities that have traditionally been considered. This paper presents the preliminary findings for Cotulla, Texas. The findings will provide more evidence supporting the importance of considering all extended factors to better illustrate the impact of shale development on rural communities.

The United States Environmental Protection Agency (US EPA) has issued a revised guidance manual on Spill Prevention, Control and Countermeasures (SPCC) plans in August 2013 for its Regional Inspectors. The manual also provides insights to the regulated community on achieving compliance with the largely performance-based SPCC regulations. The previous SPCC manual was published in November 2005. Since then, there have been revisions to the SPCC regulations in 2006, 2008, 2009 and 2011. These revisions have been incorporated into the 2013 SPCC guidance manual. The manual also includes expanded discussions of SPCC regulations that cover oil production and oil drilling and workover facilities. In addition to meeting the general SPCC requirements, the main components for oil drilling and workover facilities include positioning equipment to prevent discharges, providing catchment basins or diversion structures to intercept discharges of oil, and installing a blowout prevention assembly and well control system. For oil production facilities - in addition to the general SPCC requirements - there are requirements for bulk storage, flow-through process vessels, produced water containers, and transfer operations. Owner/operator self-certification of SPCC plans can be a cost-effective and flexible approach for the development of SPCC plans for facilities where the largest tank is either no greater than 18,900 L (5,000 gallons) (Tier I) or 37,800 L (10,000 gallons) (Tier II).

Marine black shales have long been known to contain elevated concentrations of uranium, thorium, and associated daughter products [commonly known as Naturally-Occurring Radioactive Material (NORM]). Because uranium and thorium are only marginally soluble in near-neutral groundwater and formation waters typically associated with black shales, dissolved concentrations of these elements in produced waters [technologically-enhanced NORM (TENORM)] have not been considered a serious environmental issue. In contrast, radium-226 (²²⁶Ra) and radium-228 (²²⁸Ra) are much more soluble, particularly in formation waters with high concentrations of total dissolved solids (TDS). Total radium activities in formation and produced waters typically range from 30 to 5,000 picocuries per liter (pCi/L). While total radium activities in waters produced from Marcellus Shale gas wells are commonly less than 5,000 pCi/L, activities as high as 16,000 pCi/L have been reported. When produced water reaches the land surface, changes in pressure and temperature affect the solubility of dissolved gases and, subsequently, affect the solubility of calcite, gypsum, and other minerals. These minerals commonly precipitate and form scale and sludges which can accumulate on the inside surfaces of pipes, tanks, and other water-handling equipment. Radium isotopes co-precipitate and concentrate in these mineral deposits, thereby forming a residue with higher radioactivity values than the original water. The general occurrence and speciation of radionuclides in shale samples, produced waters, scale, and sludges associated with Marcellus Shale are presented and discussed in this paper.

Due to geographic position and rich natural gas reservoir, the Eagle Ford Shale (EFS) is vulnerable to natural disasters like wildfire, tornado, flooding and chemical or gas leakage. The EFS area also lacks an effective disaster preparedness system to confront natural disasters. Timely disaster warning and evacuation guidelines can save the lives of people. In addition, a worker or a tourist may face difficulties in finding a safe area or shelter prior to the occurrence of natural and man-made disasters. For this reason, we have proposed a location-based early disaster warning and evacuation system using Integrated Mobile Sensor Environment (IMOSE). Our system comprises a Disaster Management Server (DMS), android application, sensors and users. The sensors detect chemical or gas leaks and send data on DMS. The disaster-affected area is determined by a ray casting algorithm. When our application detects the user is in a disaster zone, it will disseminate an evacuation guideline on the map of the application, including the shortest path to a shelter or safe zone. In this paper, we describe the scenarios of the emergency evacuation by two case studies: gas leak and wildfire in the Eagle Ford area.

Clean water is a valuable natural resource and is relied on for drinking, agriculture, recreation, manufacturing, energy development, tourism, and many other purposes that are essential to the public and the economy. The Clean Water Act (CWA) is the primary legislative instrument used to protect this resource. Over the past decade, though, interpretations of Supreme Court rulings have clouded definitions of "waters of the United States" (WOUS) and caused confusion about which waters and wetlands remain under the jurisdictional control of the U.S Army Corps of Engineers (USACE) and the Environmental Protection Agency (EPA). To clarify protection of waters and wetlands, the EPA and the USACE drafted guidance to sort out what the CWA covers and what may now lie beyond its reach. The guidance provides procedures for identifying waters and wetlands protected under the CWA with a focus toward protecting small waters that feed into large waters, so that downstream waters are safe from upstream pollutants. The guidance also reaffirms protection for wetlands that filter pollution and store water. The agencies propose to finalize the guidance and to continue working on rulemaking. This paper will analyze the final guidance, definitions, and jurisdiction determination procedure and how these affect the development of well pads, impoundments, access roads and water used for oil and gas development within shale plays. The central subject of this paper is to what extent does the final guidance allow the CWA to cover "non-traditional, non-navigable" wetlands and streams within shale plays, and how such guidance can be used to determine jurisdictional authority using existing scientific literature and ground truthing tools. The paper is intended to assist operators faced with a jurisdictional question involving a wetland or stream to understand what factors will allow them to determine CWA jurisdiction.

Founded in 1919, the American Petroleum Institute (API) has a long history in the development of industry standards, starting with the first standards published in 1925 on drilling thread specifications to ensure safety in the production of oil and natural gas. Continuing on for nearly 90 years, API has led the development of petroleum, petrochemical and natural gas equipment and operating standards. These standards represent the industry's collective wisdom on subjects ranging from drill bits to environmental protection. They embrace proven, sound engineering and operating practices and safe, interchangeable equipment and materials. API maintains more than 650 standards, many of which have been incorporated into state and federal regulations. API standards are also the most widely referenced oil industry standards cited by the international regulatory community. API ensures the technical relevance of its standards by maintaining its status as an American National Standards Institute (ANSI) accredited standards developing organization. As an accredited body, API's standards program undergoes regular program audits to ensure it meets ANSI's "Essential Requirements" for openness, balance, consensus and due process. API has also been the leader in the development of standards supporting sustainable shale gas development. API published its first of five specific shale gas standards in 2009 on well integrity and, subsequently, developed standards on water resource management, environmental practices, and well cementing technology. This presentation will focus on the status of updates to these standards as well as a new standard on Community Engagement being developed to ensure well operators, drilling and well servicing companies and the communities in where the shale gas is being developed fully understand the important aspects of operations taking place in and around their neighborhoods, towns, and cities.

Hydraulic fracturing - the injection of pressurized fluid (often water) to increase extraction rates and recovery of oil or gas - has become increasingly popular in combination with horizontal drilling, especially in shales in Texas. Hydraulic fracturing augments the flow of fossil fuel from a well, but requires a significant amount of water to do so. Thus, the growth in shale wells puts pressure on existing water resources, especially in drought-prone areas of Texas. Due to increased water demands in these areas, that already have low water availability, current water users and landowners have begun to sell their water resources to supply industry needs. This analysis characterizes the current state of the water market in shale-rich areas of Texas, including water pricing, type of water used, source and end use location, original intended use, and current end use — all within the water policy framework of Texas. Between 1987 and 2008, prior to the increase in hydraulic fracturing in much of Texas, the median lease price was approximately $30 per thousand cubic meters (m³) and the average price was approximately $100 per thousand m³. In this preliminary analysis, we found that - between 2009 and 2013 - the median lease price was approximately $3,100 per thousand m³ and the average price was $2,300 per thousand m³ - an increase of two orders of magnitude in the median price of water for mining water use. These prices and market trends open up the possibility for innovation and investments in technologies for water use efficiency in various sectors.

In a region traditionally known for agriculture, the Western Gulf Basin of South Central Texas has recently become a major player in the oil and gas industry. The shale gas and oil development in the area, now known as the Eagle Ford Shale region, has generated a significant boost to South Texas. However, the issue of whether the development has benefited all residents in the region (most of whom are Hispanic and low income) and how the development has affected the social life of the local communities in general, remains an unanswered question. To investigate the general economic and social impacts of the development to the local residents in the region, a research team at Texas A&M University-Kingsville has conducted a large-scale social survey in the region. Adopting a multi-stage probability sampling frame, the survey has randomly selected 1590 respondents in the region for interview. In the paper, we describe in detail the research design and survey instrument, and provide results of preliminary analysis of the data thus collected.

This paper presents a case study of the Manitoba experience in permitting petroleum-related oversize/overweight (OS/OW) truck traffic. In recent years, Southwest Manitoba, along with many regions throughout North America, has experienced rapid growth and change in the petroleum industry. This growth has fuelled economic development and also caused infrastructure challenges on rural roads that are being used by unique vehicle configurations, many of which are beyond basic truck size and weight (TSW) limits. Manitoba's OS/OW permitting program for these vehicles stems from the performance-based approach to TSW regulation being used in Canada since 1988 and relies on ongoing collaboration with the petroleum industry. Manitoba's experiences have led to several insights, which may be options for other jurisdictions facing similar issues related to OS/OW petroleum-related trucking. These insights include: (1) purposeful collaboration with the industry and officials in neighbouring jurisdictions to understand permitting needs and barriers; (2) supplementing qualitative understanding of the industry with quantitative data; and, (3) identifying opportunities to expedite permitting procedures by issuing annual permits to routinely-configured vehicles, utilizing technologies to assist with TSW enforcement, and rationalizing permit fee structures.

Geogrid use at current US drilling facilities within the Marcellus and Utica Shale regions, as well as lesser publicized shale formations, have given the Operators and Producers a way to increase the performance of their access roads and well pads. Within this market, the construction costs for these roads have increased dramatically as a direct result of the presence of areas of soft soil or unforeseen environmental impacts (e.g., cold weather). Since some of these companies have started to include geogrids into their road and well pad sections, the time for construction has been reduced, the road and well pad have been and remain stabilized and, most importantly, their construction costs have been greatly reduced. One producer in PA has saved $1.4 million in construction costs and still maintains an incredible access road that requires little to no maintenance. This paper explains how geogrids enhance performance over conventional construction methods and documents this performance through the inclusion of case histories that will help more companies in the Oil and Gas Market better understand how they can utilize this same approach in their current operations.

The incorporation of high-strength geosynthetics provide numerous benefits to oil and gas producers and the engineering consultants tasked with designing their well pads and access roads. This paper will present examples of the positive environmental impact and cost benefit high-strength geosynthetics provide Whiting Petroleum Corporation in the Williston Basin of North Dakota and Montana, along with an example of a gas well pad and access road in central Pennsylvania stabilized with the same geosynthetic. Subgrade stabilization is often required for access roads leading to the well pad and the well pad itself. Leading methods include significant depths of aggregate, chemical stabilization and geosynthetic-reinforced sections. General soft soil conditions and significant rain and snow events often require producers, engineering consultants and contractors to recommend additional aggregate to stabilize access roads and well pads. The need for additional aggregate contributes to higher traffic counts, increased CO₂ emissions and increased cost. Whiting Petroleum Corporation began exploring alternate means of stabilizing access roads and well pads in October of 2011. After reviewing various geosynthetic options and accompanying test data, the producer ultimately chose an innovative, high-strength, woven geotextile to stabilize their sites. This has led to the elimination of future maintenance and has required no additional aggregate over the life of the road and well pad. This paper will present both laboratory and full-scale test data on the performance of this innovative high-strength geosynthetic. In addition, detailed cost savings associated with eliminating additional aggregate requirements will be presented along with the environmental impact of eliminating additional aggregate hauling, placement and compaction. Case studies will be included along with photographs of well pad sites constructed both with and without this geosynthetic.

The significant impact of the truck traffic associated with the shale energy developments on local roads, including many unpaved gravel roads, has been a pressing issue while the regional economy benefits from the recent shale gas boom. In many cases, roads had to be reconstructed over a soft soil subgrade treated and stabilized by cement or lime. As an alternative, geosynthetics offer a potentially more cost-effective solution for reinforcing/stabilizing roads on soft soil subgrade. This paper presents a study using a full-scale accelerated traffic load testing to evaluate two recently-emerged geosynthetic products, a triaxial geogrid and a high-strength woven geotextile in unpaved roads built over soft soil subgrade. A total of six full-scale test sections were constructed - among which two sections were reinforced by one and two layers of triaxial geogrids, respectively - while high-strength geotextiles were used to reinforce two of the other sections with different aggregate layer thicknesses. The rest of the two sections were left as control sections, of which one section was constructed over a 30-cm-thick sand embankment. The test sections were subjected to a full-scale moving wheel load applied by the Accelerated Loading Facility (ALF). A variety of instrumentations were used to measure the load-associated and the environment-associated responses and performance of the unpaved test sections. Results of the full-scale testing on the unpaved test sections demonstrate the benefits of geosynthetics in reducing the permanent deformation/rutting.

A case study is discussed herein where non-destructive deflection testing was carried out to achieve three goals:(1) evaluate the performance of existing heavy-haul roads in Northern Alberta, Canada; (2) back-calculate insitu moduli of various materials used in the construction of these roads; and, (3) develop a heavy-haul road structural design methodology based on existing empirical and Mechanistic-Empirical design methods, while utilizing material moduli back-calculated using a thickness-independent, back-calculation approach. Heavy Weight Deflectometer (HWD) equipment was used to impact the surface of granular roads constructed with and without geosynthetics. A total of 11 haul roads were evaluated. The road structures ranged in thickness between 1.0 and 2.6 meters. Heavy loads were applied that simulate the 105-ton wheel load of the Caterpillar 797F truck. Results suggest that incorporating geosynthetic reinforcement in gravel pavements can cause pavements to behave stiffer under heavier loads (i.e., stress hardening). Moreover, Geosynthetics can be used to reduce the thickness of the road structure and save the non-renewable aggregates. HWD testing is an effective way to evaluate structural capacity and to determine in-situ material properties. A methodology is developed and successfully implemented for the design of heavy haul roads.

Trucking from shale oil and gas development destructively impacts rural, low volume, farm-to-market roads. The options for repair and reconstruction are relatively few and involve large quantities of new stone. An emerging aggregate confinement technology is being used on industrial roadways with significant success. This U.S. and Canadian patented technology - trade-named, Mechanical Concrete® - physically confines aggregates within a thin-walled structural cylinder, creating a confined-aggregate-concrete, CAC. It creates a road base with a collection of open-ended, waste-tire-derived, cylindrical segments filled with crushed stone, i.e. tire-derived-geo-cylinders, TDGC. This physical confinement process creates a porous, virtually solid material with a minimum, lab proof-tested, load-supporting capacity in excess of 1380 kPa (200 psi). On June 20, 2011, MEPCO Mining, Morgantown, WV, reopened a gravel surface road at its Mon River dock, reconstructed with a CAC base. This road handles three hundred 36,364-kg (80,000-lb) coal trucks per day. Prior to reconstruction, this road required approximately 2 truckloads of new crushed stone per week for maintenance. The new road has consistently been maintained with 2 truckloads of new stone per month, a reduction in maintenance costs of over 75%. Stone filled, tire-derived geo-cylinders are a sustainable, economical alternative for reconstructing rural roads.

In recent years, new hydraulic fracturing technologies have led to rapid shale oil and gas development. This development has included an unprecedented amount of heavy truck loading on low-volume, rural roads, many of which were not built to withstand such loading. Many highway agencies are concerned about the impact of these loads on the life of their pavements and have had to adapt to this new paradigm by developing polices to protect their infrastructure. Pennsylvania has seen extensive development of the Marcellus shale formation in recent years with significant impact to its road system. New York State has been preparing for future development of their Marcellus shale pending environmental reviews. This paper describes a variety of approaches used in Pennsylvania and New York to keep local roads safe during construction of these energy facilities and to provide fair reimbursement to municipalities for the loss in pavement service life that occurs from these activities. The engineering background is described for methods used to project long-term damage, quantify damage to specific roads, determine needs for pre-development pavement upgrades, and allocate damage costs to multiple users. The advantages and disadvantages of alternative approaches are discussed and provisions for Road Use Agreements are suggested.

While shale oil and gas developments have been a boom for the Texas economy, these developments have taken a toll on low-volume roads. Impacts of truck traffic on roads in the Eagle Ford and Barnett Shale plays and the Permian Basin are obvious in the cracks, potholes, and other major distresses. Many of Texas' Farm-to-Market, Ranch-to-Market, and local county roadway systems are not designed to withstand the heavy loads and higher traffic volumes arising from energy development. Rapid development of energy resources will continue to strain agencies until measures are taken to implement infrastructure impact plans, road-user agreements, or other measures to rehabilitate affected roadways. This paper uses case studies to explore four approaches for partnerships between energy companies, county officials, and other organizations. The proactive, performance-based approach strengthens pavements prior to energy development. The reactive, performance-based approach assesses impact fees associated with road maintenance after the damage. The third approach assesses impact fees that are not attached to actual roadway deterioration. The fourth approach uses policy changes to the Texas Transportation Code which allows counties to promote transportation infrastructure projects affected by oil and gas production activities. Funding for this approach arises from grants. The authors discuss what is currently being done in Texas and suggest recommendations for future work. With future exploration expected throughout, execution of agreements and creative reimbursement procedures will be critical to maintaining adequate levels of service and preserving working relationships between the energy industry and county governments charged with preserving roadway assets.

As oil and gas infrastructure is developed, it has become increasingly important for the roadway users (heavy haulers) to obtain release from their PennDOT roadway bonds as quickly and efficiently as possible. Heavy roadway users are interested in being released from permits on many roads across the Commonwealth of Pennsylvania to free resources for additional infrastructure construction and reduce liability for repair of damages. This presentation would serve to discuss the release process currently being used in PennDOT District 12-0. The process overview will include a discussion of the release requests, video review procedures, coordination within the District, and recommendations on best practices to achieve a timely release. In some cases, the roadway has been damaged by the users and repairs are required prior to release of the roadway bond. This presentation will also discuss the coordination required when road damage has been determined to be caused by a single and/or multiple user(s). This overview will conclude with a case study of the SR 3009 (Tom's Run Road) repair and overlay in Greene County. This project provided for the repair and installation of base repair and a new overlay on five segments (4.0 km, 2.5 miles) of state-maintained roadway. The project included coordination with two roadway contractors, six different roadway users and PennDOT staff, both in the District Office and in the Greene County Maintenance District. Hundreds of tons of asphalt were installed to provide a safe and reliable roadway to the public. The final result was a cost-controlled product that satisfied both the permit holders and PennDOT and resulted in the release of associated bonds.

The Pennsylvania Department of Transportation (PennDOT) is trying to balance the economic benefit of supporting the Shale Oil and Gas Industry while protecting the public roadway infrastructure. The Shale Oil and Gas Industry utilizes a horizontal drilling process and a separate, secondary process called hydraulic fracturing (fracing). This process releases the natural gas inside the shale formations, which are over a mile beneath the earth's surface. The fracing process requires approximately 19 million liters (5 million gallons) of water and other materials which can generate over 2,000 truck trips to the drilling pad. This truck traffic creates an exponential increase in truck volume and can severely reduce the life cycle of the roadway, which can lead to accelerated deterioration and significant repair costs. To protect PennDOT's infrastructure, numerous roadways have been posted with weight restrictions requiring haulers to obtain a permit, post security and submit a maintenance plan to utilize the roadway. In conjunction with PennDOT's efforts to protect the roadways, the Shale Oil and Gas Industry has invested time and money to work in partnership to protect, preserve, maintain and upgrade the roadway network.

This paper proposes a technique for the preliminary identification of pipes obstructed by blockages within a pipeline or a complex pipe network, relying only upon few measurements that are usually gathered to monitor the infrastructure operability. Blockages are identified as a result of an optimization procedure that minimizes the discrepancy between measured and simulated flow quantities. The framework exploits a Finite Element-like simulator of the flow problem in the system of pipes and Genetic Algorithms to perform the optimization procedure. Thermal properties of the fluid flowing inside the pipe system are considered. Results of the identification procedure are presented, and advantages and disadvantages of the procedure for the on-field implementation are outlined.

Published in September 2011, the CSA S250 — Mapping Underground Utility Infrastructure — will play a key role in the creation of more accurate and reliable as-built utility drawings and maps. CI/ASCE 38-02 - Standard Guidelines for the Collection and Depiction of Existing Subsurface Utility Data, which was published in 2003, has already been used extensively on infrastructure projects across Canada and the US. Together, these two standards form a solid foundation to both map and records utility infrastructures. The location of existing utilities can play a key role in the design and implementation of infrastructure projects associated with Shale Oil & Gas production. These impacts need to be managed properly to avoid significant cost and schedule ove runs. CI/ASCE 38-02 forms the basis for engineers to create accurate drawings of existing conditions for the project. The data proved up front is critical; however, equally important is the generation of accurate, reliable maps and drawings of new utility infrastructure placed in the ground. Creation of these new records is the primary focus of the CSA S250 Standard. The paper will review the key highlights of the new CSA S250 standard, including - standard symbology, Accuracy Levels, and data recordkeeping - and how it will improve our future knowledge of underground infrastructure. It will highlight the government and private agencies - such as the Ontario Ministry of Transportation, City of Toronto, and Fortis Gas - currently using or looking to implement the use of the standard, and identify how the knowledge learned from that exercise can assist the Shale Energy Industry. Accurate, reliable drawings of our underground utility infrastructure produced in accordance with these industry standards is a benefit to all stakeholders - Project Owners, Designers, Utilities, Regulators and Contractors. Further promotion for the use of these standards is the key if we wish to raise the bar and move forward as an industry.

Reliable underground mapping is an essential part of efficient energy production. The challenge is to determine reliable 3-D point positions in a well and/or the trajectory of a wellpath. Sensor data [e.g., measured wellbore depth (distance), wellbore inclination, and wellbore azimuth] are typically used to compute the location of discrete points in a well and a wellpath is determined using the method of minimum curvature. Part of the positioning challenge relates to specific identification of the origin, orientation of the coordinate system, knowing the quality of measurements, and knowledge of datums and map projections. Historically, survey maps showed horizontal and vertical data separately (primarily analog), but modern measurement systems produce digital 3-D spatial data. The global spatial data model (GSDM) will be described which accommodates modern measurements and 3-D digital spatial data. The GSDM uses proven rules of solid geometry to determine each 3-D position and optionally stores the standard deviation of each computed point. The subsequent relative position between any two points is easily computed and the underlying coordinate positions can be mathematically transformed to other commonly used coordinate systems. With the GSDM, all uses (site drawings, drilling, well development, production, and regulatory activities) of the position data share a common definition, and the positional uncertainty of each computed quantity can be determined from stored covariance matrices.

Railway transportation is playing a key role in the development of many new shale oil and gas reserves in North America. In the rush to develop new shale oil and gas plays, sites for railway transload terminals are often selected on the basis of land availability and environmental constraints before full consideration is given to rail design and operating requirements. The result can be terminals that poorly utilize the available space or operate inefficiently and face long-term capacity constraints. Additionally, preliminary concepts may omit or underestimate the need for staging tracks, switching leads and other rail infrastructure required to support train operations, potentially altering the economics of a terminal. To facilitate more informed decisions regarding railway terminal sites and better track layout concepts, this paper presents design requirements for bulk railway terminals to support shale oil and gas development. Guidelines for sizing facilities and layout of different track arrangements - including stub-end, inline and loop facilities - are presented. Considerations for mainline access and multi-train operation to ensure terminal capacity to support current and future demand are also discussed. Developers following these guidelines will likely obtain greater returns from their real estate and facility investments through faster railway approval of design concepts and more efficient rail operations.

Water management has become a critical link to shale resource development throughout the United States and elsewhere in the world (Wagner et. al. 2012, Arthur and Coughlin 2011). In order to stimulate production from deep shales, large volumes of water must be stored for rapid use during hydraulic fracturing operations. Although the majority of wells to date have been fractured using fresh water, there is increased emphasis on minimizing fresh water use, increasing the use of saline waters, and also recycling produced water for purposes of reuse in fracturing operations. This evolving water use strategy, combined with a diversity of operating environments, has created a number of technical and environmental challenges related to the storage of these different resources. In addition to design and water segregation considerations, there are other technical and regulatory considerations - including siting, monitoring, and maintenance activities - that are also a priority. Furthermore, the utilization of saline waters and recycling of produced water are causing the oil and gas regulatory environment to rapidly change, with several states updating pit and impoundment regulations to address the broader range of waters being utilized. This paper will discuss the management of impoundments used in unconventional resource development, including various applications, regulatory requirements, design, and best management practices.

This paper will compare the effectiveness of various types of secondary containment for storage tanks in onshore hydrocarbon production facilities. Secondary containment prevents liquid that might escape the tank from contacting the surrounding environment, especially any main water bodies. Secondary containment design is influenced by the 40-Code of Federal Regulation (CFR) Part 112 Oil Pollution Prevention and EPA's Spill Prevention Control and Countermeasure (SPCC) Guidance. This paper will summarize the acceptable methods of secondary containment construction utilized by Chesapeake Energy, which consist of polyethylene liner with and without aggregate cover, polyurea surface liner, concrete slab with wall, geo-synthetic clay liner, and compacted clay/silt berm construction. Seepage estimates will be calculated on secondary containments full of liquid with a 48-hour retention period based on time duration of daily field inspection and clean-up operations. The calculation methodology is based on diffusion and advective flows. The diffusion flow rate through soil, concrete or liner is calculated using Bernoulli's Equation on hydraulic head, and Darcy's Law on liquid flow through a permeable element. The advective flow rate through a possible defect on a liner is calculated using Touze-Foltz and Giroud's Equation. Finally, this paper will review the performance of the aforementioned secondary containment types and contrast estimated seepages with the SPCC requirement of a sufficiently impervious system.