Relative permeability has a significant impact on gas or oil and water production, but is one of the most complicated properties in unconventional reservoirs. Current understanding on relative permeability for unconventional reservoir rocks is very limited, mainly because of a lack of direct measurement of relative permeability for these rocks that have matrix permeability of sub-micron-Darcy level. Due to the difficulties related to the direct measurement, most studies on relative permeability in unconventional reservoirs are based on indirect or modeling methods. In this paper, a modified gas expansion method for shale matrix permeability measurement (Peng et al., 2019a) was adopted to measure gas relative permeability directly under the scenario of water imbibition for samples from different unconventional reservoir formations. Evolution of gas permeability, along with gas porosity and fracture-matrix interaction, during the process of water redistribution (mimic of what occurs in shut-in period in real production) were also closely measured. Results show that gas relative permeability in matrix decreases during water redistribution because of water imbibition from fracture to matrix and water block effect. Water block effect is more significant at low water saturations than higher water saturations, leading to a rapid-to-gradual drop of gas relative permeability with increasing water saturation.
A conceptual model on water redistribution in a fracture-matrix system and the change of gas and water relative permeability is proposed based on the experimental results and observations. Influencing factors including pore size, shape, connectivity, and wettability are taken into account in this conceptual model. The combined effect of these four influencing factors determines the level of residual gas saturation, which is the most important parameter in defining the shape of relative permeability curves. Water relative permeability is predicted based on the conceptual model and the measured gas relative permeability using modified Brooks-Corey equations. Deduction of oil-water relative permeability is also discussed, and experimental methods on determination of the key parameter, i.e., residual oil saturation, are proposed. Implication of relative permeability on gas or oil and water production and potential strategy for optimal production are also discussed in the paper. Hysteresis effect is not included in this study and will be addressed in future work.
Nuclear Magnetic Resonance (NMR) logging is a powerful formation evaluation technology that provides mineralogy-independent porosity and helps distinguish clay-bound water, capillary-bound water, and free fluids. NMR logging tool generally operates at 1H NMR frequency of 2 MHz (magnetic field, B0 ~ 470 Gauss) or lower. At this magnetic field, it is only feasible to detect 1H signal from fluids in pores and rely on the relaxation time variation to characterize fluid and pore types. As magnetic field strength increases, NMR sensitivity increases very dramatically and NMR signals from solid matrix can be easily detected in high field. For example, NMR at 600 MHz is about 5,000 times more sensitive than the NMR at 2 MHz. Meanwhile, the spectral resolution of high-field NMR is also greatly increased and high-field NMR spectrum can resolve the detailed differences between molecule types. Therefore, the high sensitivity and spectral resolution of high-field NMR open a totally new horizon for the characterization of geological samples, especially in organic shale reservoirs, in which organic matter and complex mineralogy remain challenging to be accurately characterized.
In this work, we report high-field NMR applications for mineral characterization, using a 600 MHz NMR spectrometer equipped with multi-channel and Magic Angle Spinning probe. Comparing to X-ray diffraction (XRD), which is the primary tool for identifying and quantifying the mineralogy of crystalline compounds in geological samples based on Bragg’s diffraction, NMR can provide more compositional and structural information for non-crystalline compounds, due to its sensitivity to local electronic binding structures.
Here we demonstrate such an application of high-resolution 27Al NMR to determine the composition and bonding chemistry of 27Al as a fingerprint for a wide range of minerals. The ratio of 27Al at tetrahedral and octahedral binding sites is quantitative and essential to differentiate the dioctahedral and trioctahedral phase. 27Al NMR can also distinguish plagioclase series members ranging from albite to anorthite end members, where Na and Ca atoms can substitute for each other. 27Al NMR can be further combined with 1H, 13C, 29Si, 25Mg, 23Na, 31P for more detailed mineral determination and clay typing. Our results show that, combining with XRD, this group of high-field NMR spectroscopic methods can greatly improve the accuracy of rock mineral and formation clay characterization in tight-rock and unconventional reservoirs.
Liang, Xing (PetroChina Zhejiang Oilfield) | Wang, Gao-Cheng (PetroChina Zhejiang Oilfield) | Pan, Feng (Schlumberger) | Rui, Yun (PetroChina Zhejiang Oilfield) | Wang, Yue (Schlumberger) | Zhang, Lei (PetroChina Zhejiang Oilfield) | Mei, Jue (PetroChina Zhejiang Oilfield) | Li, Kai-Xuan (Schlumberger) | Zhao, Hai-Peng (Schlumberger)
Understanding mineral composition and depositional mechanisms aids in evaluating gas in place and mechanical properties of shale reservoirs. A method developed to delineate mineral variations and depositional setting combines borehole elemental concentration logs with borehole electrical image logs. Borehole elemental concentration logs provide a continuous measurement of the concentrations of more than 20 elements, which data help in obtaining quantities of mineralogical constituents. Electrical borehole images are used to identify in situ depositional features. Regional mapping of variations of mineral constituents and depositional features indicates sedimentary facies distribution.
The Lower and Upper WuFeng-LongMaxi Formation was studied in 27 wells spanning 100 km west-east across the southern SiChuan basin. From elemental spectroscopy, argillaceous, carbonate, and siliceous lithologies were identified; these were examined by scanning electron microscope (SEM) to investigate their mineralogy and geological origin. Argillaceous minerals were primarily supplied by terrigenous sediments, the majority of carbonate minerals originated from chemical precipitation, and siliceous minerals are associated with siliceous-shell organisms in the Lower WuFeng-LongMaxi strata and terrigenous influx in the Upper LongMaxi strata. A transgressive lag occurring at the base of the WuFeng formation corresponds to carbonate pebbles in cores and bedding-parallel gravels on borehole images. Silty layers deposited by turbidity currents that mainly appear in Upper LongMaxi Formation were readily identified on borehole images.
The objectives of this paper are to summarize effective Reserves estimation methods for use in unconventional reservoirs, and to propose systematic procedures for classification of Resources other than Reserves (ROTR) volumes. We propose optimal timing for application of decline curve analysis (DCA), rate transient analysis (RTA), and reservoir simulation. Using these techniques, we provide results for one well from a 38-well database in the Permian Basin wells (TX USA). We then describe how the volumes are classified and categorized and how those volumes move between Reserves and ROTR as more information becomes available.
We begin with the analysis of well performance, where we specify the information that is necessary for each estimation method. We then suggest procedures to identify the flow regimes using diagnostic plots, provide guidance on the application of multi-segment DCA models, and finally suggest procedures for the application of RTA and reservoir simulation. We continue with progress toward Reserves classification, starting with suggested procedures to reclassify Prospective Resources as Contingent Resources (upon discovery). We provide post-discovery guidance on development and commerciality for the project maturity sub-classes (within the Contingent Resources classification). We explain that “established technologies” must be technically and economically viable before they can be used for development decisions. And finally, we examine requirements to remove contingencies so that the volumes can be reclassified properly as Reserves.
Our major suggestions for well performance analysis are, first, that the multi-segment DCA approach is most effective in unconventional reservoirs when specifically relevant models are used for transient flow and boundary-dominated flow. Furthermore, we suggest that RTA using analytical models expands possibilities of forecasting for changes in well conditions and for well spacing studies. Though time and computationally time consuming, compositional simulation is required for confident analysis of near-critical reservoir fluids.
For movement of resources toward Reserves, we suggest that there is no linear path to define the movement from Prospective to Contingent Resources, though there are certain criteria which must be met for a given project. Certain contingencies, such as price of oil and available technologies, dominate the classification of resource volumes.
This paper provides a visual representation of when to use each Reserves estimation method depending on available data. We present a thorough analysis of best practices for each Reserves estimation method. We provide graphical representation of the movement between Prospective to Contingent Resources categories, the progression in chance of development and commerciality within project maturity sub-classes for Contingent Resources, and the contingencies that must be resolved to move from Contingent Resources to Reserves. Finally, we present an explanation of the criteria that must be met before volumes can be reclassified and/or recategorized from undiscovered to discovered.
Xu, Feng (RIPED / CNODC) | Li, Xianbing (RIPED) | Gong, Yiwen (The Ohio State University) | Lei, Cheng (RIPED) | Li, Xiangling (RIPED) | Yu, Wei (The University of Texas at Austin / Texas A&M University) | Miao, Jijun (The University of Texas at Austin / SimTech LLC) | Ding, Yutao (CNODC)
Natural fractures are commonly observed in the unconventional reservoir. Production history indicates that natural fractures have been playing an important role in the oil and gas development progress by improving the permeability of the reservoir and increasing the well productivity. In addition, inappropriate development strategies result in the unreasonable single well oil rate, early water breakthrough, severe damages to the unconventional reservoir and overwhelming economic losses when the fracture properties and distributions are not well understood before the development. Hence, it is of great importance to propose a powerful and efficient workflow to describe the fracture distribution clearly, including building a 3D fracture model, performing history matching and forecasting productions of the unconventional reservoir. In this study, we present a powerful and practical workflow through using Fracflow software and EDFM (Embedded Discrete Fracture Model) to build the 3D DFN (Discrete Fracture Network) model. The main methodology used to perform the fracture modelling allows rigorously handling of both hydraulic fractures and natural fractures that can be identified in an unconventional reservoir. This modelling allows computing the real geometrical fracture attributes (mainly orientation and density) and the spatial distribution of fractures. Fracture conductivity values will be calibrated through a comparison of the Kh(permeability thickness) from the well test to the Kh model computed from the upscaling of the fracture model. The mentioned model above will be built by means of a stochastic simulation constrained by the results of the static and dynamic fracture characterization. In the reservoir simulation phase, EDFM processor combining commercial reservoir simulators is fully integrated to perform history matching and production performance forecast of the unconventional reservoir. With a new set of formulations used in EDFM, the non-neighboring connections (NNCs) in the EDFM are converted into regular connections in traditional reservoir simulators, and the NNCs factors are linked with gridblock permeabilities. EDFM provides three kinds of NNC pairs, transmissibility factors, and the connections between fractures and wells. With the aid of the EDFM processor, we can obtain the number of additional grids, the properties of fracture grids, and the NNCs as the simulation input. From the proposed workflow, complex dynamic behaviors of natural fractures can be captured. This will further ensure the accuracy of DFMs and the efficiency offered by structured gridding. The practical workflow for the unconventional reservoir from modelling to simulation highlights the model constrained by the results of the static and dynamic fracture characterization, and the high efficiency to model discrete fractures through the revolutionary EDFM processor. Through this workflow, we can perform history matching effectively and simulate complex fractures including hydraulic fractures and naturally fractures. It potentially can be integrated into existing workflow for unconventional reservoirs for sensitivity analysis and production forecasting.
Frac fluid delivery is selective in effect, so must fracture models. Here, a physics-based analytical model, called nine-grain model, is presented for production forecasting in multifrac horizontal wells in unconventional reservoirs, where the utilized formulation inherently enables defining three-dimensional non-uniform SRVs, selective frac-hits, and pressure- and time-dependent permeabilities. The model is validated by constructing case studies of liquid and gas reservoirs and comparing the results with numerical simulations. In cases with both production history and fracing-induced microseismic data available, the SRV's spatial structure is extracted using a hybrid four-level straight-line technique that links volumetric RTA estimations to morphometric microseismic analysis and entails plots of plasticity, diffusivity, flowing material balance and early linear flow. By applying our model to an oil well in Permian Basin, we demonstrate that the knowledge gained from the coupled microseismic-RTA contributes to resolving the non-uniqueness of RTA solutions. The proposed reservoir modeling procedure enables efficient incorporation of microseismic interpretations in modern RTA while honoring the SRV space-time variability, thus facilitates informed decision making in spacing design of wells and perforation clusters.
Frac-hits. A frac-hit can be defined as observing a perturbation in the well production rate and/or pressure that is induced by a child offset (or an infill) well, usually triggered by pressure sinks created around parent wells or high permeability lithofacies. A frac-hit that temporarily alters the parent well productivity is called a communication frac-hit, and those with long-term effects, generally caused by fracture interference, are referred as interference frac-hits. A frac-hit may also compromise the productivity of the child well itself since the existing pressure sinks distribute the fracing energy in a larger area and might lead to an asymmetric fracture growth around the child well. Besides the parent well operational condition, the microseismic monitoring of fracing can potentially indicate interference frac-hits as it reveals fracture overlaps and any preferential fracture dilation towards existing wells. Depending on the rock and fluid properties, well age, parent-child horizontal and vertical distances, and the spatial extent of Stimulated Reservoir Volume (SRV), the constructive (Esquivel and Blasingame 2017) or destructive (King et al. 2017, Ajani and Kelkar 2012) effects of frac-hits can be experienced by fractures, SRV or the entire drainage volume (stimulated and non-stimulated zones), usually by impacting rock multiphase fluid interfacial arrangements and/or changing dimensions of conductive fractures. Aside from prevention, thoroughly reviewed by Whitfield et al. (2018), it is essential to incorporate frac-hits into production forecasting models, which to date, is not yet as straightforward as their detection. Both types of frac-hits cause a change in the well productivity over time which is not necessarily correlated with pressure, and hence, complicate the reservoir modeling process.
The amount of trapped oil in hydrocarbon rich shale reservoirs recoverable through Enhanced Oil Recovery methods such as low salinity water flooding has been an ongoing investigation in the oil and gas industry. Reservoir shales typically have relatively lower amounts of swelling clays and in theory, can be exposed to a higher chemical potential difference between the native and injected fluid salinity before detrimental permeability reduction is experienced through the volumetric expansion of swelling clays. This fluid flux into the pore spaces of the rock matrix acting as a semi permeable membrane is significant enough to promote additional recovery from the extremely low permeability rock. The main goal of this paper is to determine how osmosis pressure build up within the matrix affects geomechanical behavior and hydrocarbon fluid flow. In this study we investigate Pierre shale samples with trace amount of organic content and high clay content as an initial step to fully understanding how the presence of organic content affects the membrane efficiency for EOR applications in shales using low salinity fluid injection. The same concept is also valid when slickwater is utilized as fracturing fluid as majority of the shale reservoirs contain very high salinity native reservoir fluid that will create large salinity contrast to the injected slickwater salinity.
The organic-rich reservoir shales typically have a TOC content of approximately 5 wt% or higher with TOC occupying part of the bulk matrix otherwise to be filled up by clays and other minerals. With less clay within the rock structure, the amount of associated clay swelling arising from rock fluid interaction will be limited. The overall drive of water into the matrix brings added stress to the pore fluid known as osmotic pressure acting on the matrix that also creates an imbalance in the stress state. The native formation fluid with salinity of 60,000 ppm NaCl has been used while 1,000 ppm NaCl brine is utilized to simulate the low salinity injection fluid under triaxial stress conditions in this phase of the study reported here. A strong correlation is obtained between the osmotic efficiency and effective stress exerted on the shale formation. The triaxial tests conducted in pursuit of simulating stress alteration under the osmotic pressure conditions and elevated pore pressure penetration tests indicated that the occurrence of swelling directly impact the formation permeability. These structural changes observed in our experimental results are comparable to field case studies.
Anderson, Iain (Heriot-Watt University) | Ma, Jingsheng (Heriot-Watt University) | Wu, Xiaoyang (British Geological Survey) | Stow, Dorrik (Heriot-Watt University) | Underhill, John R. (Heriot-Watt University)
This work forms part of a study addressing the multi-scale heterogeneous and anisotropic rock properties of the Lower Carboniferous (Mississippian) Bowland Shale; the UK's most prospective shale-gas play. The specific focus of this work is to determine the geomechanical variability within the Preese Hall exploration well and, following a consideration of structural features in the basin, to consider the optimal position of productive zones for hydraulic fracturing. Positioning long-reach horizontal wells is key to the economic extraction of gas, but their placement requires an accurate understanding of the local geology, stress regime and structure. This is of importance in the case of the Bowland Shale because of several syn- and post-depositional tectonic events that have resulted in multi-scale and anisotropic variations in rock properties. Seismic, well and core data from the UK's first dedicated shale-gas exploration programme in northwest England have all been utilized for this study. Our workflow involves; (1) summarizing the structural elements of the Bowland Basin and framing the challenges these may pose to shale-gas drilling; (2) making mineralogical and textural-based observations using cores and wireline logs to generate mineralogy logs and then to calculate a mineral-based brittleness index along the well; (3) developing a geomechanical model using slowness logs to determine the breakdown stress along the well; (4) placing horizontal wells guided by the mineral-based brittleness index and breakdown stress. Our interpretations demonstrate that the study area is affected by the buried extension of the Ribblesdale Fold Belt that causes structural complexity that may restrict whether long-reaching horizontal wells can be confidently drilled. However, given the thickness of the Bowland Shale, a strategy of production by multiple, stacked lateral wells has been proposed. The mineralogical and geomechanical modelling presented herein suggests that several sites retain favorable properties for hydraulic fracturing. Two landing zones within the Upper Bowland Shale alone are suggested based on this work, but further investigation is required to assess the impact of small-scale elastic property variations in the shale to assess potential for well interference and optimizing well placement.
Three different types of analysis were performed on high-frequency bottomhole pressure data acquired in the Hydraulic Fracturing Test Site (HFTS; Ciezobka et al., 2018) program. The pressure data was made available by Laredo Petroleum Incorporated (LPI) and the Gas Technology Institute (GTI) through participation in the HFTS joint industry project. Rate transient analysis (RTA), pressure interference test (PIT) analysis, and reservoir pressure depletion analysis of production and pressure data were performed to better understand the performance of these hydraulically fractured Wolfcamp reservoirs of the southeastern Midland Basin. Unconventional RTA, PIT analysis, and reservoir depletion analysis of the HFTS pressure data provides three different perspectives to describe fracture systems in the formation. The study of these combined attributes of this unique dataset provides new insights about pressure communication and reservoir drainage of the Wolfcamp A and Wolfcamp B in the HFTS area.
Hydraulic fractures generated during multi-stage hydraulic fracturing operations often have complex geometries (Cipolla et.al, 2008). Estimating the dimensions of complex fracture networks is one of the biggest challenges of evaluating hydraulically fractured reservoirs. Utilizing high frequency bottomhole pressure (BHP) data, unconventional RTA provides a method to evaluate effective fracture dimensions with advantages of low marginal cost and simplicity. Chu et al. (2017) demonstrated the workflow to analyze multiphase rate transient data using examples of Permian Wolfcamp horizontal wells. In this study, a similar workflow is applied to BHP data collected from 11 Wolfcamp horizontal wells in the HFTS project.
High frequency BHP data collected during well interference tests can also be utilized to identify inter-well communication. Over the years, spacing between wells on a multi-well pad has been altered, along with fracture designs, to improve reservoir development efficiency. Larger fracturing treatments have been performed to increase well productivity. Interaction between nearby producing wells is more likely to happen with increasing fracture length and closer well spacings. Understanding the magnitude of fracture communication is therefore important for optimizing well spacing with fracturing treatment sizes. Communication between producing wells can be detected from pressure response at an observation well to significant rate changes at an active well, such as a shut-in (SI) or bring-online (BOL). The process is called a pressure interference test (PIT). PITs are widely used in conventional reservoirs to determine inter-well reservoir properties (Kamal, 1983). In unconventional shale reservoirs, analysis methods to understand the pressure interference test results have been developed in recent years. Sardinha et al. (2014) analyzed pressure interference between wells in Horn River Basin by calculating pressure hit percentage. Awada et al. (2015) identified the interference response time by looking at pressure derivatives. Roussel and Agrawal (2017) applied poroelastic geomechanical models to interpret pressure interference data and calculate fracture dimensions. In the HFTS project, two PITs were conducted among 11 horizontal wells at different times of production. Kumar et al. (2018) analyzed interference data from the first PIT by calculating field response times between source and observation wells. In this discussion, we follow the technique presented by Chu et al. (2018) for analyzing power-law PIT data to quantitatively diagnose well communication among HFTS wells. The magnitude of pressure interference (MPI) between communicating wells is calculated and compared for two PIT sequences conducted 18 months apart.
Almost simultaneously, advances were made in understanding both the processes within the source rock organic matter that accompany the generation and expulsion of hydrocarbons and in the acquisition, processing, and quantitative interpretation of 3D seismic data. In particular, as organic matter in shales in unconventional plays generates and expels hydrocarbons, porosity is formed in the organic matter and the organic matter becomes more dense and more brittle. As these changes are occurring at a micro-scale, extraction of hundreds of different attributes from a well-imaged 3D seismic volume has made it possible to observe changes at a macro-scale in seismic lines and horizons within that volume. Seismic attributes derived from pre-stack inversions yielding rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density, when calibrated with well log and/or core measurements, can be combined to calculate TOC, pore pressure, rigidity, and compressibility because these properties cause fundamental changes in how seismic waves travel through the rock.
Equally important, the escalation in computing power via methods such as machine learning, neural networks, and multivariate statistics has made it possible to interpret large amounts of data. All of these innovations have contributed to better identification of sweet spots within unconventional plays. Such sweet spots include areas with elevated TOC values, enhanced porosity, and zones that can be targeted for fracking.
One of the primary advantages of seismic data is that it provides information in those areas in between control points/wells. This information in turn helps operators to better select targets for wells and for landing zones. Carefully tied 3D seismic inversion and integration with petrophysical and rock data further allow for detailed characterization of unconventional reservoirs. The enhanced ability to identify the best potential drilling targets has significant economic implications in terms of risk reduction and improved chances to find economic prospects.
While 3D seismic data is being used routinely by numerous companies to predict the mechanical properties, density, and associated TOC of many formations, there is yet to be a direct link made between TOC loss, kerogen conversion, and the associated changes in rock properties. This work documents the importance of TOC loss during maturation and its effects on rock properties like porosity, density, brittleness, and how those advances coupled with the advances in quantitative interpretation of 3D seismic data are enabling the unconventional operators to predict location, thickness, landing zone, and sweet spots with appropriately acquired, processed, and interpreted 3D seismic. Meticulously calibrated 3D seismic inversion and integration with petrophysical and rock data permit detailed reservoir characterization of unconventional reservoirs.
Updated methods for the back calculation of original TOC have been developed using well logs, rock measurements, and 3D basin modeling to assist in locating and developing unconventional reservoirs. In addition, petrophysical measurements that reflect TOC and porosity and are related to fundamental properties controlling the seismic response can be extracted from the seismic reflection data. In turn, seismic attributes derived from pre-stack inversions yielding rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density, when calibrated with well log and/or core measurements, can be combined to estimate TOC, pore pressure, rigidity, and compressibility because these properties cause basic modifications in how seismic waves travel through the rock.
This study shows advancements in studies of: 1) TOC loss with increased thermal maturation, 2) how this loss affects the development of organic porosity, 3) how kerogen becomes denser, harder, and more brittle with increasing maturity, and 4) how recent developments in quantitative interpretation workflows for 3D seismic data facilitate estimation of TOC and determination of rock mechanical properties from shear (Vs) and compressional (Vp) velocities and density. Further integration of geochemical, geomechanical, and geophysical technologies and measurements will provide improved estimates of present-day TOC that can in turn be extended to relative maturity and percent conversion.
Examples provided in this work illustrate prediction of present-day TOC, porosity, density, and mechanical properties extracted from high fidelity pre-stack inversion. Pre-stack inversion along with machine learning can be used to predict rock properties such as porosity, TOC, organic matter quality, rigidity, and pressure and to correlate those properties back to well productivity for improved execution. Relating present TOC estimated from seismic to TOC loss and kerogen property changes with increasing maturity is possible by combining the results of these technologies.
Though analysis and inversion of painstakingly acquired modern 3D seismic data is capable of estimating porosity, TOC, matrix strength, and pore pressure, the latest work on rock property changes as hydrocarbons mature and are expelled isn't typically addressed in most studies. Increasing communication between disciplines might improve estimation of these properties and extend the capability to assess the extent of TOC loss during maturation and the porosity increases that accompany it. This ability is especially important in the intra-well regions where the potential of 3D seismic to extend data between control points enables better reserve estimates and high grading of acreage. After carefully calibrating a quantitative 3D seismic interpretation with a 3D basin modeling analysis of the source rock potential and maturity, an operator is better prepared to high grade acreage and attain the most economic development of unconventional resources.
The escalation in computing power means there are hundreds of different attributes that can be extracted or calculated from a well-imaged 3D seismic volume. Using quantitative calibration of fundamental geochemical measurements such as TOC, pyrolysis, and petrographic measurements of vitrinite reflectance that yield the quantity, quality, and maturity of organic matter in combination with well log and seismic data creates a model for identifying sweet spots and the areas in the target formation that exhibit high TOC, high porosity, and elevated brittleness. Further integration and calibration of changes occurring at the micro-level in organic matter in unconventional plays with their impact on the signatures of data at the macro-level can provide information on the types of hydrocarbons most likely to be found in these sweet spots as well as identifying which zone(s) in the target formation are most likely to be amenable to fracking. Used together, the advances outlined here result in a technological evolution that could have a substantial impact on: 1) the approach to and 2) the economics of the exploration and production of unconventional plays.