Jennifer Lynne Miskimins

Measurements of methane emissions at natural gas production sites in the United States

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. Engineering estimates of methane emissions from natural gas production have led to varied projections of national emissions. This work reports direct measurements of methane emissions at 190 onshore natural gas sites in the United States (150 production sites, 27 well completion flowbacks, 9 well unloadings, and 4 workovers). For well completion flowbacks, which clear fractured wells of liquid to allow gas production, methane emissions ranged from 0.01 Mg to 17 Mg (mean = 1.7 Mg; 95% confidence bounds of 0.67–3.3 Mg), compared with an average of 81 Mg per event in the 2011 EPA national emission inventory from April 2013. Emission factors for pneumatic pumps and controllers as well as equipment leaks were both comparable to and higher than estimates in the national inventory. Overall, if emission factors from this work for completion flowbacks, equipment leaks, and pneumatic pumps and controllers are assumed to be representative of national populations and are used to estimate national emissions, total annual emissions from these source categories are calculated to be 957 Gg of methane (with sampling and measurement uncertainties estimated at ±200 Gg). The estimate for comparable source categories in the EPA national inventory is ∼1,200 Gg. Additional measurements of unloadings and workovers are needed to produce national emission estimates for these source categories. The 957 Gg in emissions for completion flowbacks, pneumatics, and equipment leaks, coupled with EPA national inventory estimates for other categories, leads to an estimated 2,300 Gg of methane emissions from natural gas production (0.42% of gross gas production).

Mechanical anisotropy in the Woodford Shale, Permian Basin Origin, magnitude, and scale

The rock mechanical properties of shales are critical to how they perform as reservoirs, determining both their tendency to develop natural fractures and their response to hydraulic stimulation. These mechanical properties are, in turn, manifestations of composition, fabric and porosity, and fluid saturations. Such properties also dictate the seismic response of shales, as well as their signature on many well logs. It has long been recognized, or perhaps assumed, that shales are relatively homogeneous in the plane parallel to bedding and relatively heterogeneous in the direction perpendicular to bedding.

The Effects of Fracturing Fluids on Shale Rock Mechanical Properties and Proppant Embedment

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 Youngs 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. Introduction In geology, shale has traditionally been defined as a sedimentary rock containing high percentages (more than 50%) of clays and lower percentages of silica or carbonate minerals (Britt and Schoeffler, 2009). However, many of the shale prospects that are currently being developed in the petroleum industry are not shales, as defined in geology. They are, instead, “prospective shale” reservoirs, which are fine-grained clastics that are characterized by their ultra low permeability and usually composed of silica and carbonate with a small amount of clay minerals (Britt and Schoeffler, 2009). Generally, shale rocks have been considered as source rocks for conventional oil and gas reservoirs. However, with technological evolution in the petroleum industry, such as hydraulic fracturing, the rising oil and gas prices, as well as the escalating demand for fossil fuels, these rocks are increasingly regarded as the source, the seal, and the reservoir. Subsequently, development of such reservoirs is becoming more and more technically and economically feasible. The reasons behind the success of these shale systems are largely dependent on excellent hydraulic fracturing designs that require a good understanding of the mechanical properties of the subject and confining formations. In hydraulic fracturing design, Youngs modulus is one criterion used to define the most appropriate fracturing fluid and other design considerations. Youngs modulus provides an indication of how much fracture conductivity, kfw, can be expected due to width and embedment considerations. Without adequate fracture conductivity, production from the hydraulic fracture will be minimized if not completely eliminated. This paper discusses conditions where Young’s modulus is shown to decrease

Experimental Investigation of Cryogenic Fracturing of Rock Specimens Under True Triaxial Confining Stresses

We have performed a laboratory study of cryogenic fracturing for improving oil/gas recovery from low-permeability shale and tight reservoirs. Our objective is to develop well stimulation techniques using cryogenic fluids, e.g. liquid nitrogen (LN) to increase permeability in a large reservoir volume surrounding wells. The new technology has the potential to reduce formation damage created by current stimulation methods as well as minimize or eliminate water usage and groundwater contamination. The concept of cryogenic fracturing is that sharp thermal gradient (thermal shock) created at the rock surface by applying cryogenic fluid can cause strong local tensile stress and initiate fractures. We developed a laboratory system for cryogenic fracturing under true triaxial loading, with a liquid nitrogen delivery/control and measurement system. The loading system simulates confining stresses by independently loading each axis up to about 5000 psi on 8 8 8 cubes. Both temperature in boreholes and block surfaces and fluid pressure in boreholes were continuously monitored. Acoustic and pressure-decay measurements are obtained before and at various stages of stimulations. Cubic blocks (8 8 8 ) of Niobrara shale, concrete, and sandstones have been tested, and stress levels and anisotropies are varied. Three schemes are considered: gas fracturing without cryo-stimulation, gas fracturing after low-pressure cryogen flow-through, gas fracturing after high-pressure flow-through. Pressure decay results show that liquid nitrogen stimulation clearly increases permeability, and repeated stimulations further increase the permeability. Acoustic velocities and amplitudes decreased significantly following cryo-stimulation indicating fracture creation. In the gas fracturing without the stimulation, breakdown (complete fracturing) occurs suddenly without any initial leaking, and major fracture planes form along the plane containing principal stress and intermediate stress directions as expected theoretically. However, in the gas fracturing after cryogenic stimulations, breakdown occurred gradually and with massive leaking due to thermal fractures created during stimulation. In addition, the major fracture direction does not necessarily follow the plane containing principal stress direction, esp. at low confining stress levels. In tests, we have observed that cryogenic stimulation seems to disrupt the internal stress field. The increase of borehole temperature after stimulation affects the permeability of the specimen. While a stimulated specimen is still cold, it keeps high permeability because fractures remain open and local thermal tension is maintained near the borehole. When the rock becomes warm again, fractures close and permeability decreases. In these tests, we have not used proppants. Overall, fractures are clearly generated by low and high-pressure thermal shocks. The added pressure of the high-pressure thermal shocks helps to further propagate cryogenic fractures generated by thermal shock. Breakdown pressure is significantly lowered by LN stimulation with breakdown pressure reductions up to about 40% observed.

THE IMPORTANCE OF GEOPHYSICAL AND PETROPHYSICAL DATA INTEGRATION FOR THE HYDRAULIC FRACTURING OF UNCONVENTIONAL RESERVOIRS

Multidisciplinary integration is common in the petroleum industry and is critical for the success of many projects. This paper discusses the need for and importance of multidisciplinary integration of data inputs for the success of hydraulic fracturing treatments in unconventional reservoirs, specifically tight-gas sands and shale systems. Four main areas are discussed, including microseismic, field-wide seismic, petrophysical rock properties, and geological characterization. A discussion of future areas for integration is also provided.

Simulation of Non-Darcy Porous Media Flow According to the Barree and Conway Model

Non-Darcy porous media flow has been traditionally handled using the Forchheimer equation. However, recent experimental studies have shown that the Forchheimer model is unable to fit laboratory results at high flow rates. On the other hand, the non-Darcy flow model, proposed by Barree and Conway, is capable of describing the entire range of relationships between flow rate and potential gradient from low- to high-flow rates through proppant packs. In this paper, we present a numerical model by incorporating the Barree and Conway model into a general-purpose reservoir simulator for modeling single-phase and multiphase non-Darcy flow in porous and fractured media. The numerical formulation is based on the TOUGH2 methodology, i.e., spatial integral-finite-difference discretization, leading to an unstructured grid, followed by time discretization carried out with a backward, first-order, finite-difference method. The final discrete nonlinear equations are handled fully implicitly by Newton iteration. In the nu...

A Fully-Coupled Geomechanics and Flow Model for Hydraulic Fracturing and Reservoir Engineering Applications

In this paper we present a practical fullycoupled geomechanics and flow model for application to hydraulic fracturing, especially in tight gas reservoirs, and other reservoir engineering applications. The mathematical formulation is consistent with conventional finitedifference reservoir simulation code to incl ude any number of phases, components and even thermal problems. In addition, the propagation of strain displacement front as a wave, and the relevant changes in stress with time, can be tracked through the wave component of the geomechanics equations. We show the development of an efficient finitedifferenc e computer code for rock deformation including thermal and wave propagation effects. The numerical approach chosen uses two different control volumes—one for fluid and heat flow and another one for rock deformation. The ultimate goal is to provide a tool to assess the effect of pore pressure, cooling or heating the reservoir, and propagation of a strain wave resulting from hydraulic fracturing on the reservoir rock frame. This information is crucial for determining the effect of shear stress on opening or closing of natural fractures during creation of hydraulic fractures, and changes in shearand compressionalwave velocities for seismic imaging purposes. A specific application of the product of this research is to simulate fracture propagation, gel cleanup and water block issues in hydraulic fracturing. The modeling results indicate significant change in shear stresses near hydraulic fractures as a result of hydraulic fracture face displacement perpendicular to the fracture face and not as much from pore pressure change because the filtrate does not travel very far into the reservoir. Similarly, temperature change effects are also very significant in changing stress distribution.

A Comparison of Hydraulic-Fracture Modeling With Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System

...................................................................................................................... iii LIST OF FIGURES ........................................................................................................... ix LIST OF TABLES.......................................................................................................... xvii ACKNOWLEDGMENTS ............................................................................................. xviii DEDICATION................................................................................................................. xix CHAPTER

Calculation and Implications of Breakdown Pressures in Directional Wellbore Stimulation

In 1898, Kirsch published equations describing the elastic stresses around a circular hole that are still used today in wellbore pressure breakdown calculations. These equations are standard instruments used in multiple areas of petroleum engineering, however, the original equations were developed strictly for vertical well settings. In today’s common directional or horizontal well situations, the equations need adjusted for both deviation from the vertical plane and orientation to the maximum and minimum horizontal in-situ stress anisotropy. This paper provides the mathematical development of these modified breakdown equations, along with examples of the implications in varying strike-slip and pore pressure settings. These examples show conditions where it is not unusual for breakdown pressure gradients to exceed 1.0 psi/ft and describes why certain stages in porpoising horizontal wells experience extreme breakdown issues during hydraulic fracturing treatments. The paper also discusses how, in most directional situations, the wellbore will almost always fail initially in a longitudinal direction at the borehole wall, after which the far-field stresses will take over and transverse components can be developed. Tortuosity and near wellbore friction pressure can actually add to forcing the initiation of such longitudinal fractures, which can then have cascading effects on other growth parameters such as cluster-tocluster and stage-to-stage stress shadowing. Special considerations for highly laminated anisotropic formations, where shear failure of the wellbore may precede or preclude tensile failure, are also introduced. Such failure behaviors have significant implications on near wellbore conductivity requirements and can also greatly impact well production and recovery efforts.

Simulation of Deep-Coalbed-Methane Permeability and Production Assuming Variable Pore-Volume Compressibility

One of the horizons of interest for future unconventional-resource development is deep- (>5,000 ft) coalbed-methane (CBM) production. Unfortunately, coal permeability is highly sensitive to changes in stress, leading to the belief of limited permeability in deep coals. However, this conclusion is generally based on the assumption of constant pore-volume (PV) compressibility of a coals porosity/ cleat system during changing stress conditions. Modelling the evolution of permeability within potential deep coal reservoirs is highly dependent on this assumption of constant or variable PV compressibility. This paper shows how this assumption affects modelled permeability changes and that permeability in deep coals may maintain much higher values during production than previously suggested. Using prior work and data, ideas are reorganized into an alternative view of deep-CBM permeability. The modelled compressibility and permeability results are then applied to the simulation of deep-CBM reservoirs to discover the practical difference of the compressibility assumption on a coals simulated production. Simulations show significant difference in production based on the two assumptions. Application of the simulation results may provide a justification for exploration into deeper CBM reservoirs.