Significance This work reports direct measurements of methane emissions at 190 onshore natural gas sites in the United States. The measurements indicate that well completion emissions are lower than previously estimated; the data also show emissions from pneumatic controllers and equipment leaks are higher than Environmental Protection Agency (EPA) national emission projections. Estimates of total emissions are similar to the most recent EPA national inventory of methane emissions from natural gas production. These measurements will help inform policymakers, researchers, and industry, providing information about some of the sources of methane emissions from the production of natural gas, and will better inform and advance national and international scientific and policy discussions with respect to natural gas development and use.

A Buckley and Leverett type analytical solution is derived for non-Darcy displacement of immiscible fluids in porous media, in which non-Darcy flow is described using the general model proposed by Barree and Conway. Recent laboratory studies and analyses have shown that the Barree and Conway model is able to describe the entire range of relationships between rate and potential gradient from low-to high-flow rates through porous media, including those in transitional zones. We also present a general mathematical and numerical model for incorporating the Barree and Conway model to simulate multiphase non-Darcy flow in porous and fractured media, while flow in fractured rock is handled using a general multi-continuum approach. The numerical solution of the proposed multiphase, non-Darcy flow model is based on a discretization scheme using an unstructured grid with regular or irregular meshes for multi-dimensional simulation. The final discretized nonlinear equations are handled fully implicitly with the Newton iteration. As an application example, we use the analytical solution to verify the numerical solution for and to obtain some insight into one-dimensional non-Darcy displacement of two immiscible fluids according to the Barree and Conway model. Overall, this work provides an improved platform for modeling multiphase non-Darcy flow in oil and gas reservoirs, including complex fractured systems such as shale gas reservoirs. Influence of an immobile or mobile saturation on non-Darcy compressible flow of real gases in propped fractures, The effect of an immobile liquid saturation on the non-Darcy flow coefficient in porous media, Effects of non-Darcy flow on the constant-pressure production of fractured wells, Soc. Pet. Eng. J., pp.390-400, 1981. Helfferich, F. G., Theory of multicomponent, multiphase displacement in porous media, Soc. Pet. Eng. J., 51-62, 1981. Hirasaki, G. J., Application of the theory of multicomponent, multiphase displacement to three-component, two-phase surfactant flooding, Soc. Pet. Eng. J., 191-204, 1981. Hirasaki, G. J. and G. A. Pope, Analysis of factors influencing mobility and adsorption in the flow of polymer solution through porous media, Soc. Pet. Eng.

a b s t r a c tWhile hydraulic fracturing has revolutionized hydrocarbon production from unconventional resources, waterless or reduced-water fracturing technologies have been actively sought due to concerns arising from the heavy use of water. This study investigates the feasibility of fracture stimulation by using cryogenic fluids to create a strong thermal gradient generating local tensile stress in the rocks surrounding a borehole. Cracks form when the tensile stress exceeds the material's tensile strength. This mechanism has not been exploited in the context of stimulation and may be used to fracture reservoir rocks to reduce or eliminate water usage. This paper reports initial results from a laboratory study of cryogenic fracturing. In particular, we have developed experimental setups and procedures to conduct cryogenic fracturing tests with and without confining stress, with integrated cryogen transport, measurements, and fracture characterization. Borehole pressure, liquid nitrogen, and temperature can be monitored continuously. Acoustic signals are used to characterize fractures before and after the experiments. Cryogenic tests conducted in the absence of the confining stress were able to create cracks in the experimental blocks and alter rock properties. Fractures were created by generating a strong thermal gradient in a concrete block semi-submerged in liquid nitrogen. Increasing the number of cryogenic stimulations enhanced fracturing by both creating new cracks as well as widening the existing cracks. By comparing the cryogenic fracturing results from unstressed weak concrete and sandstone, we found that the generation of fractures is dependent on the material properties. Water in the formation expands as it freezes and plays a competing role during cryogenic cooling with rock contraction, thus is an unfavorable factor. A rapid cooling rate is desired to achieve high thermal gradient.

The development of shale reservoirs has grown significantly in the past few decades, spurred by evolving technologies in horizontal drilling and hydraulic fracturing. The productivity of shale reservoirs is highly dependent on the design of the hydraulic fracturing treatment. In order to successfully design the treatment, a good understanding of the shale mechanical properties is necessary.Some mechanical properties, such as Young's modulus, can change after the rock has been exposed to the hydraulic fracturing fluids, causing weakening of the rock frame. The weakening of the rock has the potential to increase proppant embedment into the fracture face, resulting in reduced conductivity. This reduction in conductivity can, in turn, determine whether or not production of the reservoir will be economically feasible, as shale rocks are characterized by their ultra-low permeability, and conductivity between the reservoir and wellbore is critical. Thus, shale reservoirs are associated with economic risk; careful engineering practices; and a better understanding of how the mechanical properties of these rocks can change are crucial to reduce this risk.This paper discusses various laboratory tests conducted on shale samples from the Bakken, Barnett, Eagle Ford, and Haynesville formations in order to understand the changes in shale mechanical properties, as they are exposed to fracturing fluids, and how these changes can affect the proppant embedment process. Nanoindentation technology was used to determine changes of Young's modulus with the application of fracturing fluid over time and under high temperature (300 °F) as well as room temperature. Mineralogy, porosity, and total organic content were determined for the various samples to correlate them to any changes of mechanical properties. The last part of the experiments consisted of applying proppants to the shale samples under uniaxial stress and observing embedment using scanning acoustic microscope.The results of this study show that maximum reduction of Young's modulus occurs under high temperature and in samples containing high carbonate contents. This reduction in Young's modulus occurs in "soft" minerals as well as the "hard" rock-forming minerals. This reduction of modulus can cause the effective fracture conductivity to decrease significantly.

With a global paradigm shift towards exploring shale reservoirs, the industry focus has moved towards optimizing hydraulic fracturing in these reservoir types. Low-viscosity slickwater fracture treatments are commonly used as a completion technique in these ultra-low permeability reservoirs. Each shale reservoir is different due to the presence of in situ natural fractures and other geologic complexities, and thus the resultant hydraulic fracture network is distinct and the proppant transport in these "created" complex fracture networks is not clearly understood. Much speculation exists in the industry as to how efficiently the proppant is transported from the primary fracture into subsidiary fractures, if it is at all. A better awareness of proppant movement in complex fracture networks can possibly help with better hydraulic fracture treatment designs by focusing on parameters that enhance transport in the subsidiary fractures and understanding what impacts this transport may have on the resulting production. This paper discusses a series of tests carried out in a low-pressure laboratory setting to evaluate proppant transport in complex fracture networks. Different slickwater treatment scenarios were simulated by pumping sand slurry through a series of complex slot configurations while varying the slot complexity, pump rate, proppant concentration, and proppant size. Results from twenty-seven tests carried out provide some interesting insights into the nature of proppant transport and settling in complex fracture networks. In the case of a primary slot system, the proppant transport was observed to occur via traction carpet after the creation of a proppant dune. However, in the case of secondary slots, the proppant transport was found to be dependent on the dune buildup in the primary slot. Two mechanisms were observed to be transporting the proppant into the secondary slots: 1) proppant flowing around the corner at pump rates higher than the threshold pump rate (related to the threshold velocity in the primary slot), and 2) proppant falling from the primary slot due to the effects of gravity, regardless of the pump rate.

During the past two decades, hydraulic fracturing has significantly improved oil and gas production from shale and tight sandstone reservoirs in the United States and elsewhere.Considering formation damage, water consumption, and environmental impacts associated with water-based fracturing fluids, efforts have been devoted to developing waterless fracturing technologies because of their potential to alleviate these issues. Herein, key theories and features of waterless fracturing technologies, including Oil-based and CO 2 energized oil fracturing, explosive and propellant fracturing, gelled LPG and alcohol fracturing, gas fracturing, CO 2 fracturing, and cryogenic fracturing, are reviewed. We then experimentally elaborate on the efficacy of liquid nitrogen in enhancing fracture initiation and propagation in concrete samples, and shale and sandstone reservoir rocks. In our laboratory study, cryogenic fractures generated were qualitatively and quantitatively characterized by pressure decay tests, acoustic measurements, gas fracturing, and CT scans. The capacity and applicability of cryogenic fracturing using liquid nitrogen are demonstrated and examined. By properly formulating the technical procedures for field implementation, cryogenic fracturing using liquid nitrogen could be an advantageous option for fracturing unconventional reservoirs.

Summary This paper presents the results of our new experimental studies conducted for high flow rates through proppant packs, which show that the Barree and Conway (2004) flow model is capable of overcoming limitations of the Forchheimer non-Darcy equation at very high flow rates. To quantify the non-Darcy flow behavior using the Barree and Conway model, a numerical model is developed to simulate non-Darcy flow. In addition, an analytical solution is presented for steady-state linear non-Darcy flow and is used to verify the numerical-simulation results. The numerical model incorporates the Barree and Conway model into a general-purpose reservoir simulator for modeling multidimensional, single-phase non-Darcy flow in porous and fractured media and supplements the laboratory findings. The numerical model is then used to perform sensitivity analysis of the Barree and Conway flow model's parameters and to investigate transient behavior of non-Darcy flow at an injection well.

Recent laboratory studies and analyses (Lai et al. Presented at the 2009 RockyMountain Petroleum Technology Conference, 14-16 April, Denver, CO, 2009) have shown that the Barree and Conway model is able to describe the entire range of relationships between flow rate and potential gradient from low-to high-flow rates through porous media. A Buckley and Leverett type analytical solution is derived for non-Darcy displacement of immiscible fluids in porous media, in which non-Darcy flow is described using the Barree and Conway model. The comparison between Forchheimer and Barree and Conway non-Darcy models is discussed. We also present a general mathematical and numerical model for incorporating the Barree and Conway model in a general reservoir simulator to simulate multiphase nonDarcy flow in porous media. As an application example, we use the analytical solution to verify the numerical solution for and to obtain some insight into one-dimensional non-Darcy displacement of two immiscible fluids with the Barree and Conway model. The results show how non-Darcy displacement is controlled not only by relative permeability, but also by non-Darcy coefficients, characteristic length, and injection rates. Overall, this study provides an analysis approach for modeling multiphase non-Darcy flow in reservoirs according to the Barree and Conway model. List of SymbolsA Cross-section area of flow, m 2 A i j Common interface area between the connected blocks or nodes i and j, m 2 C β non-Darcy constant, m 0.25 D Depth from a datum, m D i Distance from the center of block i to the common interface of blocks i and j f β Fractional flow of phase β, fraction flow β mass flux of fluid β, kg/s g Gravitational acceleration constant, m/s 2 k d Darcy permeability, m 2 k min Minimum permeability at high rate, m 2 k mr Minimum permeability ratio, relative to Darcy permeability, fraction k rβ Relative permeability to fluid β, fraction N Total number of nodes/elements/gridblocks of the grid P β Pressure of fluid β, Pa P cgo Gas-oil capillary pressure, Pa P cgw Gas-water capillary pressure, Pa P cow Oil-water capillary pressure, Pa ∇ P Pressure gradient, Pa/m q Injection rate, m 3 /sec q β Mass sink/source per unit volume for the fluid β, kg/m 3 Q Fluid volumetric flow rate, m 3 /s Q βi Mass sink/source term at element i, for the fluid β, kg/m 3 R i Residue term of mass balance at element i, kg S β Saturation of fluid β, fraction S β Average saturation of fluid β, fraction t Time step size, s V i Volume of block i, m 3 v β Velocity of fluid β, m/s x sw Location of the specific saturation, m Greeks α Angle from horizontal plane, Degree β Non-Darcy coefficient, 1/m ρ β Fluid density of fluid β, kg/m 3 μ β Viscosity of fluid β, Pa s τ Characteristic length, 1/m φ Effective porosity of the medium, fraction ∇ Flow potential gradient, Pa/m