Shale gas is defined as natural gas occurring in shale formations. It is an unconventional energy resource, which has become an increasingly important source of natural gas globally and has the potential to grow as a major energy source in the next decade. However, production of shale gas remains technically and economically challenging. Having high total organic content and falling in the gas window (302 F–392 F), shale has sufficient potential to generate huge amounts of natural gas. Generally, natural gas is stored in a shale matrix, which is highly porous but has very poor permeability.
Flashback 10 years ago to 2008: the North American hydraulic fracturing industry utilized a then record breaking 21.41 Billion pounds and experienced exponential growth year-over-year (excluding 2015 and 2016). Prior to 2008, proppant demand grew at a relatively modest pace and overwhelmingly consisted of 20/40 mesh high quality natural sands and synthetic proppants. Fundamental changes in drilling and completion practices has given rise to a significant increase in the application of smaller mesh proppants, most notably 40/70, 30/50 and various forms of what is generically referred to as 100 mesh sand (i.e., sands that are predominantly smaller than 70 mesh) in natural gas and liquid applications. Proppant demand has now soared, increasing significantly as a result of the new high-intensity completions practices in horizontal wells. In 2018, an estimated 200 Billion pounds will be used for the first time in history (or 10 times that used in 2008).
The proppant supply industry responded well to the increased demand in the past decade, but the industry is increasingly concerned about future supply limitations and the potential impact on completion practices subject to high volume, quality and mesh size availability.
This paper summarizes the historical supply of proppant by type and source, and the driver for each proppant type based on the authors’ current and prior research. The paper will further clarify the basics of proppant by type and size (e.g., what is 100 mesh?) and will address some of the challenges that both the proppant supplier and end-user may face subject to current or desired completion practices. Key observations will be: 1) Potential limitations in the amount of proppant size and type, 2) The impact that specific proppant shortages may have on both supplier and end-user, and 3) Risk factors the proppant supply base may experience subject to future changes in completion design.
The objective of this effort is to encourage the need to study alternative completion designs subject to proppant availability. It is specifically not the intent of this paper to propose one form of completion practice or proppant type over the other.
Tuxen, Anders (Danish Technological Institute) | Boughrara Salman, Amina (TWI Ltd.) | Davis, John (TWI Ltd.) | L. Pedersen, Poul (Danish Technological Institute) | L. Byg, Casper (Danish Technological Institute) | Frederiksen, Maj (Danish Technological Institute) | A. Hansen, Jacob (Danish Technological Institute) | N. Skov, Søren (Danish Technological Institute) | T. Kjeldsen, Kasper (Danish Technological Institute) | Hone, Jim (HGL Dynamics Ltd.) | Wood, Andrew (HGL Dynamics Ltd.) | T. Craster, Bernadette (TWI Ltd.) | Shillam, Jason (HGL Dynamics Ltd.)
Analysis of dissolved methane and volatile organic compounds (VOCs) in water is crucial in monitoring the underground water quality, specific to shale oil and gas subsurface activities. Existing methods for monitoring these analytes generally rely on manual sampling at hydrogeological boreholes followed by off-line chromatography-based laboratory analysis. These methods are labor intensive and prone to errors. In addition, they do not capture the dynamic variations, which are particularly interesting in the occurrence of methane. In this work, a new sensor-based instrumentation for in-situ detection and measurement of methane and VOCs in subsurface environments is presented. The methane detection method relies on the Non-Dispersive Infrared technology whereas VOCs are detected using the principle of photoionization detection.
It is demonstrated that the system has a relatively short response time combined with low detection limits for methane and VOCs. This makes the system suitable for monitoring aquifers in shale gas exploration sites with a fairly high temporal resolution thus giving information on dynamic variations in the methane and VOC concentrations.
As well construction technology enables ever-longer horizontal reach, the challenge increases for proppant placement in hydraulic fracturing operations. Effectively placing conventional proppants (sand and ceramic) in extended-reach wells requires either high pump rates or high-viscosity fluids and are subject in both cases to early proppant settling and banking. Even when heavily gelled fluids are used, proppant suspensions are subject to particle settling in the presence of vibration, and/or due to fracturing fluids breaking before the fracture closes. Furthermore, the fractures are typically vertical; and in this case the proppant has a tendency to settle in the lower portion of the fractures while the upper portions close in the absence of proppant. This can lead to impairment in the geometry of the fracture and well productivity. Using proppant with much lower densities than that of conventional proppant will provide better transport. Another benefit from these ultra-lightweight proppants (ULWP) is the elimination of polymer damage with the use of low-polymer or slick water fluid systems, enabled by their extremely slow settling rates.
Since the mid-2000s, ULWP has been used in over 3000 wells to overcome placement and settling challenges. Taking advantage of low-viscosity fluids, ULWP have been used as nearly neutral buoyant proppant; thus, minimizing settling within the created fracture and leading to a better placement. In this study, the hydraulic treatment and production data of those wells treated with ULWP and offset wells were carefully reviewed. Main production metrics are calculated to evaluate the production performance.
Nagoo, A. S. (Nagoo & Associates) | Kulkarni, P. M. (Equinor) | Arnold, C. (Escondido Resources) | Dunham, M. (Bravo Natural Resources) | Sosa, J. (Jones Energy) | Oyewole, P. O. (Proline Energy Resources)
In this seminal work, we reveal for the first time an extensively field-tested, demonstrably accurate and simple analytical equation for the calculation of the critical gas velocity limit (or onset of liquid flow reversal) in horizontal wells as an explicit and direct function of diameter, inclination and fluid properties. For the independently verifiable and first-of-its-kind multi-play field validation study, we carefully assimilate a very large database of actual horizontal gassy oil and gas liquid loading wells from several unconventional U.S. shale plays with different bubble point and dew point fluid systems and varying gas-to-liquid ratios and varying water cuts. The shale plays in our validation database include the Eagle Ford, Woodford, Cleveland Sands, Haynesville, Cotton Valley, Fayetteville, Marcellus and Barnett formations within their associated Western Gulf, South Texas, Arkoma, Western Anadarko, East Texas, Appalachian and Permian basins. Then, after summarizing our comprehensive field testing results, practical production optimization applications of the new analytical equation and advanced use cases of interest are further highlighted in various liquid loading prediction and prevention scenarios.
As opposed to prior critical gas velocity calculation methods (droplet reversal-based, film reversal-based, flow structure stability/energy), video observations both in the lab and the field clearly show continuously-evolving, co-existing and competing flow structures even with simple fluids without mass exchanges. Therefore, this work avoids skewed assumptions on demarcating the prevailing or dominant flow structure. Instead, the new analytical equation developed is based on an analysis of the major forces in the flow field, namely the axial buoyancy vector, the convective inertial and the interfacial tension forces, in combination with an assumption of the onset of liquid flow reversal based on flow field bridging (Taylor instability). Since the new analytical equation was formulated using these minimalist assumptions, this unique characteristic results in the highest predictability obtainable for the critical gas velocity calculation because there is the least amount of uncertainties (fudge factors). The consistent accuracy of the equation against our extensive horizontal well liquids loading database verifies this fact. Moreover, the simplicity of form of the equation makes it easy to use in that every practicing engineer in practice can perform fast hand or spreadsheet calculations. In effect, this equates to having a model as simple as the Turner model but now with additional direct functions of diameter and inclination. Also, the results clearly invalidate the need for artificial variables (such as interfacial friction factor) that cannot be directly measured in any experiment. In terms of usage, the new model is used in liquid loading prevention scenarios such as end-of-tubing (EOT) landing optimization and tubing-casing selection. Evidently, this work proves that no complex, computer-only procedure is necessary for accurate critical gas velocity calculation. This finding has significant speed and improved answer-reliability implications in strong favor of the presented simple equation for use in artificial lift, production optimization and digital oilfield software in industry, in addition to being ideally suited for ‘physics-guided data analytics’ applications in real-time production operations environments.
According to Energy Information Administration (EIA), production of shale gas and associated gas from tight oil plays will be the largest contributor to natural gas production growth, accounting for nearly two-thirds of the total U.S. production by 2040 (EIA, 2017). Therefore, much effort has been made to investigate the development mechanisms of unconventional reservoirs. However, it is a great challenge to fully understand the phase-and flow-behavior of shale oil and gas due to the dominance of nano-sized pores and the heterogeneity of the porous geometries.
Myths and Facts of Forecasting Horizontal Well Production in Unconventional Reservoirs - Are We Complicating a Simple Analysis? This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Accurate prediction of long-term performance of multi-frac horizontal wells (MFHW) targeting unconventional reservoirs is still a challenge due to variability in reservoir properties, well spacing, stimulation design, and production optimization strategies. The use of type curves to normalize the aforementioned variables has been adopted by operating companies mainly for reserves booking and as a benchmark for well performance.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC.
ABSTRACT: Rebound hardness (RHN) has recently gained considerable interest as a rock mechanical parameter in the petroleum industry. However, few published studies target a comprehensive integration among RHN and reservoir parameters, which can be highly valuable in reservoir characterization and production. This study focuses on the integration among RHN and facies, mineralogy, natural fractures, reservoir quality, and rock mechanical properties of the unconventional “Mississippian Limestone” play in north-central Oklahoma, USA. In 2415 feet (736 m) of core, RHN correlates with porosity, permeability, and critical rock mechanical properties, suggesting its potential value as a quick and inexpensive tool in reservoir characterization and production design. RHN exhibits varying patterns in relation to porosity and permeability in different play areas, likely related to different depositional settings and sampling bias. Therefore, the prediction of reservoir quality from RHN should be tailored among different play areas with a well-defined sampling protocol. Results also indicate that RHN correlates well with mineralogy but exhibits limited variability among many fractured and non-fractured zones. This suggests that the present-day rock mechanics are likely a combination of earlier “unaltered” and later “altered” characteristics, indicating that the temporal evolution of rock mechanical properties should be considered in reservoir characterization and production design.
The “Mississippian Limestone” Play, located primarily in Oklahoma and southern Kansas (Figure 1), has been developed using conventional vertical drilling techniques for over half a century and has recently become one of the most active unconventional resource plays in North America. The associated strata - the “Mississippian Limestone” (MISS) - is an informal stratigraphic nomenclature which includes the Mississippian (Early Carboniferous)-aged strata present across the U.S. Southern Mid-Continent, including parts of Kansas, Missouri, Arkansas, and Oklahoma (Figure 1). As opposed to the historic “Mississippian Limestone” play, there are several recently discovered play areas nearby that target the Mississippian section, such as the “STACK” play southwest of the “Mississippian Limestone” play area (Figure 1).
Fracture height is a critical input parameter for 2D hydraulic-fracturing-design models, and also an important output result of 3D models. Although many factors may influence fracture-height evolution in multilayer formations, the consensus is that the so-called “equilibrium height belonging to a certain treating pressure” provides an upper limit. However, because of the complexity of the algebra involved, published height models are overly simplified and do not provide reliable results.
We revisited the equilibrium-height problem, started from the definition of the fracture stress-intensity factor (SIF), considered variation of layered formation properties and effects of hydrostatic pressure, and developed a multilayer fracture-equilibrium-height (MFEH) model by use of the programming software Mathematica (2017). The detailed derivation of SIF and work flow of MFEH model are provided.
The model is compared with existing models and software, under the same ideal geology condition. Generally, MShale (2013) calculated smaller height, and FracPro (2015) larger height, than the MFEH model. Most of the difference is attributable to the different interpretation of the “net pressure,” and the solving of the nonlinear equations of SIF as well. In the normally stressed case, they are both acceptable, although MShale is more reliable. The discrepancy is much larger when there is abnormally high or low stress in the adjacent layers of the perforated interval. The effects of formation rock and fluid properties on the fracture-height growth were investigated. Tip jump is caused by low in-situ stress, whereas tip stability is imposed by large fracture toughness and/or large in-situ stress. If the fluid density is ignored, the result regarding which tip will grow into infinity could be totally different. Second and even third and fourth solutions for a three-layer problem were found by Excel experiments and this model, and proved unrealistic; however, they can be avoided in our MFEH model. The full-height map with very-large top- and bottom-formation thicknesses shows the ultimate trend of height-growth map (i.e., when the fracture tip will grow to infinity) and suggests the maximum pressure to be used. To assess the potential effects of reservoir-parameter uncertainties on the height map, two three-layer pseudoproblems were constructed by use of a multilayer formation to create an outer- and inner-height envelope.
The improved MFEH model fully characterizes height evolution amid various formation and fluid properties (fracture toughness, in-situ stress, thickness, and fluid density), and for the first time, rigorously and rapidly solves the equilibrium height. The equilibrium height can be used to provide input data for the 2D model, improve the 3D-model governing equations, determine the net pressure needed to achieve a certain height growth, and suggest the maximum net pressure ensuring no fracture propagation into aquifers. This model may be incorporated into current hydraulic-fracture-propagation simulators to yield more-accurate and -cost-effective hydraulic-fracturing designs.