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The Geomechanics Of A Shale Play: What Makes A Shale Prospective
Abstract
Many shale plays are being successfully developed throughout North America. These shale plays are being evaluated based on a number of criteria but primarily through typical unconventional and tight formation gas reservoir characteristics. Prospective shale plays share several interesting characteristics such as mineralogy, rock mechanics, and geomechanics. It is the intent of this paper to highlight and demonstrate the inter-relationship of these characteristics and show their importance on completion and stimulation design and more importantly to the very prospectivity of an unconventional shale play.
This paper will show through an analysis of the mineralogy that shale plays are made up of mostly silica and carbonate material and have few clay constituents. In other words, the prospective shale's are actually fine-grained clastics and not shale!
Secondly, prospective shale's tend to be brittle with the static Young's Modulus generally in excess of 3.5 x 106 psi. Of course this brittleness is related to the lack of clay constituents that make up these rocks. In addition, prospective shales tend to satisfy clastic correlations of dynamic to static Young's Modulus. They do not behave like typical shales but more like fine-grained isotropic (on a core scale) clastics!
Finally, gas can flow through induced fractures or natural fissures under effective stress conditions in these shale plays. As a result, water-frac treatments are the stimulation of choice! However, proppant is still necessary in at least the near wellbore vicinity to provide a conductive pathway to the wellbore.
This paper focuses on three key elements (mineralogy, rock mechanics, and geomechanics) of prospective shale plays and benefits the petroleum industry by:Integrating the laboratory core work with multi-disciplinary data to develop a shale and unconventional reservoir prospectivity evaluation tool,Illustrate how this multi-disciplinary dataset influences completion and stimulation design, execution, and well performance, andDemonstrate how this multi-discipline dataset can be used to identify and mitigate well completion and stimulation risks in these unconventional reservoirs.
Introduction
There are a number of important parameters and technical disciplines that need to be addressed to understand the viability of an unconventional gas reservoir. Unconventional gas reservoirs are somewhat unique, in that, they require "good" reservoir, completion, and fracture stimulation for success. Failure of any one of these key disciplines means a marginal or uneconomic well and success in all three may not guarantee a successful well as they are extremely price/cost sensitive.
On the reservoir side Gunter 1–2 and Newsham and Rushing 3–4 correctly tie the geology, petrophysics, and reservoir engineering to develop an integrated work flow for tight and unconventional gas reservoirs. The four stage model included:large scale geologic architecture,description of the rock and fluid systems,definition of flow units through formation evaluation, andcalibration of the geologic and petrophysical models through reservoir simulation.
Geomechanics was addressed throughout their workflow. Stage 1 of their work addressed the large scale structural components of the geologic model such as faults, in-situ stresses, and fissures, Stage 2 addressed the stress dependent properties and anisotropy of the rocks, and stage 3 and 4 addresses the hydraulic fracture and natural fissure orientations and effects on well performance.
Slatt 5 et al. developed a workflow for unconventional gas shales that included (1) characterization of multi-scale sedimentology and sequence stratigraphy, (2) relate stratigraphy to log response, (3) seismic response, (4) petrophysical and geomechanical properties, and (5) organic geochemistry. In this work, the geomechanics of the prospect are brought in through step 4 and although not discussed in any great detail a relationship between mineralogy and geomechanics is suggested. Further, the authors recommend additional attention be given to the lithologic properties of the shale and the brittleness or ductility.
... Suitability of reservoir rocks for fracturing is determined based on their brittleness. Also, the stability of the wellbore and reservoir after drilling and production is determined by the mechanical properties of the involved rock mass (Fam et al., 2003;Dewhurst et al., 2011;Britt and Schoeffler, 2009). Quartz content positively affects the brittleness of the tested mudstone and oil shale rocks , Ma, et al., 2019, which is manifested in high Young's modulus and low Poisson's ratio (high brittleness index) and result in more complex fracture geometry as shown in Figure 1 (Grieser and Bray, 2007). ...
... (1) Quartz, however, can be found in several forms, such as biogenic, detrital, and diagenetic, with different properties (Slatt, 2011). In general, a shale rock with a Young's modulus larger than 24 GPa is identified as brittle and more suitable for hydraulic fracturing (Britt and Schoeffler, 2009). Prospective shale formations (appropriate for hydraulic treatment) contain more silica and carbonate than clay minerals and this makes them quite brittle compared to typical shales that the higher clay content makes them ductile. ...
... Prospective shale formations (appropriate for hydraulic treatment) contain more silica and carbonate than clay minerals and this makes them quite brittle compared to typical shales that the higher clay content makes them ductile. On a core-scale, the perspective shales behave like fine-grained clastic rocks rather than typical shales, as they fit the static to dynamic Young's modulus ratio correlations developed for clastic rocks (Britt and Schoeffler, 2009). Figure 2 shows the dynamic Young's modulus (measured by acoustics) versus the static Young's modulus (measured by triaxial compression tests) for clastic rocks, prospective shales, and nonprospective rocks. ...
As major oil and gas companies have been investing in shale oil and gas resources, even though has been part of the oil and gas industry for long time, shale oil and gas has gained its popularity back with increasing oil prices. Oil and gas industry has adapted to the low-cost operations and has started investing in and utilizing the shale oil sources significantly. In this perspective, this study investigates and outlines the latest advances, technologies, potential of shale oil and gas reservoirs as a significant source of energy in the current supply and demand dynamics of oil and gas resources.
A comprehensive literature review focusing on the recent developments and findings in the shale oil and gas resources along with the availability and locations are outlined and discussed under the current dynamics of the oil and gas market and resources. Literature review includes a broad spectrum that spans from technical petroleum literature with very comprehensive research using SCOPUS database to other renowned resources including journals and other publications. All gathered information and data are summarized. Not only the facts and information are outlined for the individual type of energy resource but also the relationship between shale oil/gas and other unconventional resources are discussed from a perspective of their roles either as a competing or a complementary source in the industry. In this sense, this study goes beyond only providing raw data or facts about the energy resources but also a thorough publication that provides the oil and gas industry professional with a clear image of the past, present and the expected near future of the shale oil/gas as it stands with respect to other energy resources.
Among the few existing studies that shed light on the current status of the oil and gas industry facing the rise of the shale oil are up-to-date and the existing studies within SPE domain focus on facts only lacking the interrelationship between heavy and light oil as a complementary and a competitor but harder-to-recover form of hydrocarbon energy within the era of rise of renewables and other unconventionals. This study closes the gap and serves as an up-to-date reference for industry professionals.
... These fractures provide hydraulic access deeper into the reservoir and allow gas to be collected from a larger region of the rock ( Haimson and Fairhurst, 1969;Pye, 1973;Economides et al., 20 0 0 ). Fracking relies on the brittle failure of shale, but the mechanical properties of shale depend strongly on the composition ( Economides et al., 20 0 0;Rickman et al., 20 08;Britt and Schoeffler, 2009 ); many hydrocarbon-bearing shales have high clay content and may therefore have non-negligible ductility ( Vallejo, 1988;Daigle et al., 2014;Swift et al., 2014;Vega et al., 2014 ). Both laboratory and field data suggest that the ductility of shales can have an important impact on the success of fracking ( Haimson and Fairhurst, 1969;Britt and Schoeffler, 2009 ), but the ductility of shales is almost always neglected. ...
... Fracking relies on the brittle failure of shale, but the mechanical properties of shale depend strongly on the composition ( Economides et al., 20 0 0;Rickman et al., 20 08;Britt and Schoeffler, 2009 ); many hydrocarbon-bearing shales have high clay content and may therefore have non-negligible ductility ( Vallejo, 1988;Daigle et al., 2014;Swift et al., 2014;Vega et al., 2014 ). Both laboratory and field data suggest that the ductility of shales can have an important impact on the success of fracking ( Haimson and Fairhurst, 1969;Britt and Schoeffler, 2009 ), but the ductility of shales is almost always neglected. Most studies also neglect fluid flow through the shale due to its extremely low permeability ( e.g., Hubbert and Willis, 1957;Wang and Dusseault, 1991a;Detournay, 2004 ). ...
... As such, we adopt M ∼ 50 GPa and ˘ ∼ 27 GPa (Young modulus Ȇ ∼ 25 GPa and Poisson ratio ν ∼ 0.36) and a porosity of φ ref f ∼ 0 . 20 as typical properties of sedimentary rocks such as sandstones and shales ( e.g. , Goodman, 1980;Hart and Wang, 1995;Bobko and Ulm, 2008;Rickman et al., 2008;Britt and Schoeffler, 2009;Bobko et al., 2011 ). We further assume moderate internal friction and cohesion, ϕ ∼ 35 • and c ∼ 120 MPa, but very little dilation, ψ ∼ 0.3 • ( Vermeer and De Borst, 1984;Mandl, 2005;Bobko and Ulm, 2008;Bobko et al., 2011 ). ...
Flow-induced failure of granular materials is relevant to a broad range of geomechanical applications. Plasticity, which is the inherent failure mechanism of most granular materials, enables large deformations that can invalidate linearised models. Motivated by fluid injection into a borehole, we develop a steady-state model for the large deformation of a thick-walled, partially-permeable, elastic–perfectly-plastic annulus with a pressurised inner cavity. We account for pre-existing compressive stresses, as would be present in the subsurface, by subtracting a compressed initial state from our solutions to provide the additional disturbance due to fluid injection. We also introduce a simple parameter that allows for a smooth transition from an impermeable material (i.e., subject to mechanical loading at the inner wall) to a fully permeable material (i.e., subject to an internal pore-pressure gradient), which would be relevant to coated boreholes and very-low-permeability materials. We focus on the difference between poroelastic and poroelasto-plastic deformations, the role of kinematic and constitutive nonlinearity, and the transition from impermeable to fully permeable. We find that plasticity can enable much larger deformations while predicting much smaller stresses. The former makes model choice increasingly important in the plastic region, while the elastic region remains insensitive to these changes. We also find that, for a fixed total stress at the inner wall, materials experience larger deformations and generally larger stresses as they transition from impermeable to fully permeable.
... Dynamic Young's modulus (at high differential stress) versus static Young's modulus of these Horn River shale core samples are plotted on top of Britt and Schoeffler (2009) data as seen in Figure 10. Figure 10 shows that these shale samples fall in the "prospective shales" category defined by Britt and Schoeffler (2009). Figure 11 shows that this well is dominantly "brittle" according to Dong et al. (2017c) ductile-brittle categorization, hence, a "good candidate well" for hydraulic fracturing in the Horn River basin. ...
... Dynamic Young's modulus (at high differential stress) versus static Young's modulus of these Horn River shale core samples are plotted on top of Britt and Schoeffler (2009) data as seen in Figure 10. Figure 10 shows that these shale samples fall in the "prospective shales" category defined by Britt and Schoeffler (2009). Figure 11 shows that this well is dominantly "brittle" according to Dong et al. (2017c) ductile-brittle categorization, hence, a "good candidate well" for hydraulic fracturing in the Horn River basin. ...
... Dynamic at about 6000 psi differential stress versus Static Young's Modulus Correlation of Horn River Shale (this study) overlaid inBritt and Schoeffler (2009) data showing Horn River Shale cores selected from the given well fall in the prospective shale region from a rock mechanics point of view. ...
... The clay content in excess of thirty five (35) percent to forty (40) percent are to too high to be considered as widely perspective for shale gas reservoir [8]. The data was collected from 8 shale prospects with above 40% clay constituents [8]. ...
... The clay content in excess of thirty five (35) percent to forty (40) percent are to too high to be considered as widely perspective for shale gas reservoir [8]. The data was collected from 8 shale prospects with above 40% clay constituents [8]. Both of the prospects are producing gas, but no viable economic play has been made. ...
The brittleness and ductility of Setap Shale from Bekenu, Beluru and Long Lama area can be shown by analyzing the relationship between Poisson’s Ratio and Young’s Modulus. Both Young’s Modulus and Poisson’s Ratio can be calculated using P-wave and Swave value from ultrasonic velocity test. Ultrasonic velocity analysis on core samples from Bekenu, Beluru and Long Lama shows typical values of Poisson’s ratio and static Young’s Modulus of shale. The mineral composition of samples was analyzed using X-ray diffraction (XRD). Beluru 3 was described as marl samples shows significant number of quartz and dolomite which increase the density of the rock higher than Bekenu and Long Lama area. In the other hand, the Long Lama-5 sample shows high ductility compares to other location due to high clay constituents. High clay constituents can be defined by clay constituents greater than 40% composition. The shale with more than 40% are “true shale” where it may affect the conductivity of hydraulic fracturing phase due to high ductility. High ductile shale has the ability to re-seal the fracture due to high elastic material content. The brittleness of shale shows strong relationship between the mineralogical composition of the shale at different locality of Setap Shale and its elastic properties as different samples show different mineral composition.
... However, specimens from the Georgina Basin generally have a lower UCS and higher Young's modulus than cited samples from the USA. Other studies have found that a higher Young's modulus is favourable for tensile fracturing as it promotes deformation through fracturing rather than through plastic flow, as would a clay-rich specimen (Bodziak et al., 2014;Britt & Schoeffler, 2009). The success of stimulation in the Barnett Shale is widely attributed to its high silica content that results in a stiff and brittle behaviour (Altamar & Marfurt, 2014). ...
... The success of stimulation in the Barnett Shale is widely attributed to its high silica content that results in a stiff and brittle behaviour (Altamar & Marfurt, 2014). The Georgina Basin samples all have Young's modulus greater than 25 GPa, the minimum value cited for prospective shale plays (Britt & Schoeffler, 2009), and all but one sample are above 48 GPa. ...
Middle Cambrian sediments in the southern Georgina Basin contain multiple organic-rich source rocks and have been suggested to be prospective for both conventional and unconventional hydrocarbons. We present new geomechanical data collected from the middle Cambrian Arthur Creek Formation and Thorntonia Limestone in four wells (Baldwin 1, MacIntyre 1, Owen 2, Todd 1) in the southern Georgia Basin, and compare the data to mineralogical and geochemical datasets. Geomechanical test intervals were selected to allow geomechanical test results to be directly compared with the mineralogical and geochemical datasets (X-Ray Diffraction, HyLogger and organic geochemistry). Approximately 25 m of core was tested for unconfined compressive strength (UCS) using the scratch-testing technique, and results indicate values in the range of 60–150 MPa. Triaxial testing was also conducted to measure the poroelastic properties of core, and results indicated that Young’s modulus is generally in the range of 45–67 GPa. UCS and Young’s modulus are positively correlated and increase with depth through the prospective Arthur Creek Formation. The mechanical properties of the tested core are relatively indurated and stiff compared with young sedimentary rocks and broadly similar to proven shale gas plays in Australia and internationally. Mineralogically, the Georgina Basin rocks tested have lower clay contents than rocks from other Australian and international basins but no clear correlation was observed between geomechanical properties and mineralogy, suggesting that multiple factors contribute to the poroelastic and strength parameters. For example, parameters such as sonic velocity and porosity are weakly correlated to rock strength. Geomechanical data can be used alongside other datasets (e.g. sedimentological, geophysical and structural data) to better inform predictions of hydrocarbon prospectivity.
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KEY POINTS
• Middle Cambrian rocks from the Georgina Basin, Australia are prospective for conventional and unconventional hydrocarbons.
• Rock mechanical tests are conducted to determine how the organic-rich sediments might respond to stimulation.
• Mechanical analyses are evaluated alongside mineralogical, geochemical and well-log data to assess controls on rock strength properties.
• Geomechanical behaviour is complex and appears to be driven by multiple factors.
... The former is represented by the properties defining reservoir potential such as organic content, thermal maturity, mineralogy, porosity, hydrocarbon saturation, formation volume whereas, the latter is represented by elastic moduli properties such as Young's modulus and Poisson's ratio and rock hardness attributes of a formation (Diaz et al., 2013;Ahmed, 2017). These parameters help in understanding the conditions under which a rock fails thus aiding in the reservoir simulation through hydraulic fracturing (Warpinski et al., 2009;Britt and Schoeffler, 2009;Soliman et al., 2012). The knowledge of geomechanical properties of gas shales is fundamental in ascertaining their suitability for keeping the resulting fracture network open during hydraulic fracturing (Britt and Shoeffler, 2009;Josh et al., 2012;Wood and Hazra, 2017). ...
This paper presents laboratory investigations on the vertically
drilled borehole specimens belonging to the Barren Measure
Formation shales in the Raniganj sub-basin, India. These shales
were examined for their mineralogical makeup and geomechanical
properties through a series of laboratory experiments viz. X-ray
diffraction, uniaxial tests, single-stage triaxial tests, tensile strength
tests, porosity, and permeability measurements. The mineralogical
assessment has revealed dominant clay minerals and moderate silica
content. The mechanical tests yielded a high Young’s modulus and
low Poisson’s ratio in these shales with brittle to semi-brittle type
of failure. The compositional, elastic and tensile brittleness of these
shales indicate values that are in good agreement with the brittle
nature of gas shales. Furthermore, these shales report low porosity
and ultra-low permeability. The Barren Measure Formation in
the Raniganj sub-basin is organically rich and was targeted during
India’s first exploratory well, yielding natural gas. However, these
shales are still in their infancy in terms of their geomechanical
attributes. This study also attempted to generate basic data on
properties like compressibility, elastic moduli, and tensile strength,
which are among the critical parameters controlling the reservoir
simulation program. The results of brittleness and failure
parameters (elastic moduli, internal friction angle, cohesion,
compressive strength and tensile strength) of Barren Measure
Formation in Raniganj sub-basin of Damodar Basin, India show
high similarity with those of Roseneath Formation in Cooper Basin,
Australia revealing their analogous origin.
... In these reservoirs, the expelled hydrocarbon remains trapped in the shale source rock. These types of reservoirs require unconventional methods to extract hydrocarbons (Britt and Schoeffler 2009). Horizontal drilling and hydraulic fracturing (HF) have become an increasingly important for economic production of oil and natural gas in places where hydrocarbons were previously inaccessible, such as shale plays. ...
Hydraulic Fracturing (HF) is the prime technology for enhanced production from shale plays. Due to their laminations at different scales, shales exhibit transverse isotropic (TI) properties. In most cases the lamination planes are nearly horizontal with the symmetry axis being vertical, therefore, shales are referred to as TI vertical (TIV) rocks. This significantly influences the initiation and propagation of the induced fractures during fracturing operation. However, many studies on HF modeling in shales assume isotropic medium to simplify the problem. The anisotropic toughness is a distinct feature of layered formations such as shales, and its modelling is important to estimate the hydraulic fracturing initiation pressure, as well as the fractures geometry. In this work, to address the effect of TIV properties of the rock, we used the anisotropic toughness to develop the analytical models for fracture initiation pressure (FIP) based on data from the Bakken Shale, as a case study. In particular, we used ResFrac for calculations, which is a fully 3D HF and reservoir numerical simulator. Different scenarios of radial fracture for cases of single and multiple fractures were simulated for isotropic and anisotropic toughness conditions. The results showed that the hydraulic fracture initiation and propagation are strongly affected by the toughness anisotropy. An increase in the magnitude of anisotropy in toughness leads to an increase in the FIP. We also observed that the FIP varies with direction and consequently the fracture becomes more elongated in the direction of the minimum toughness and contained in the direction of the maximum toughness. In the case of multiple HFs, the combined effect of the anisotropy and the stress shadow was observed. This effect was stronger in the anisotropic case compared to the isotropic case. Hence, the isotropic approximation for TIV shale rocks can lead to inaccurate prediction of FIP and incorrect fracture morphology that can possibly affect the HF design.
... The boom in unconventional plays in recent decades requires deeper understanding of the geomechanical properties and in situ stress characteristics of shale gas reservoirs. The refined understanding of the rock properties and in situ stress facilitates reservoir evaluation, drilling, wellbore stability, and well stimulation (Britt and Schoeffler, 2009;Britt, 2012;Zheng et al., 2018;Clarke et al., 2019;Wang et al., 2019;Zoback and Kohli, 2019). The mechanical properties of shales are significantly different from those of common rock types (e.g., sandstones and carbonates) characterized by heterogeneity, ...
The stress-strain relationship in shales is generally time-dependent. This concerns their long-term deformation in unconventional reservoirs, and its influence on the in situ stress state therein. This paper presents an experimental investigation on the time-dependent deformation of the Longmaxi shale gas shale. A series of creep experiments subject the shale samples to long-term, multi-step triaxial compression. It is found that the shale samples exhibit varying degrees of time-dependent deformation, which can be adequately described by a power-law function of time. The experimental results establish the relationship between the elastic Young’s modulus and viscoplastic constitutive parameters, which are different from previous those derived from North American shales. Based on this viscoplastic constitutive model, the stress relaxation and the differential stress accumulation over geologic time scales can be estimated. It is found that linear elasticity substantially overestimates the differential stress accumulation predicted in the context of viscoplastic relaxation. The characterized viscoplasticity and stress relaxation are of vital importance for various geomechanical problems in shale reservoirs.
... With the extensive exploitation of heavy oil fields in China, a group of scholars have also made significant contributions to the study of heat transfer during steam injection [37][38]. Hu expounded the concept and simple calculation method of the total heat transfer coefficient of the wellbore on the basis of the predecessors. ...
Heavy oil resources are an important part of the future energy structure worldwide. The main method of heavy oil extraction is thermal extraction. Reasonable selection of steam injection parameters is of great significance to reduce the heat loss of pipelines and wellbore, increase the service life of pipes and wellbore, and improve the economic benefits of heavy oil production. In this paper, the actual field data is used to analyze the sensitivity of various steam injection parameters including boiler outlet parameters and wellhead injection parameters. The research results show that under the same steam injection rate, the heat loss rate increases with the increase of pipeline length; as the steam injection rate increases, the heat loss rate gradually decreases. The steam quality of the bottom hole increases slightly with the increase of steam injection time, but the increase is not very large. The bottom hole steam pressure gradually decreases with the increase of steam injection rate. For the same steam injection rate, when the steam injection rate is small (steam rate ≤ 150 t/d), the bottom steam pressure is greater than the wellhead steam pressure; on the contrary, when the steam rate is large When, the bottom steam pressure is less than the wellhead steam pressure. As the dryness of the injected steam at the wellhead increases , the heat loss rate at the bottom of the well gradually decreases. With the increase of wellhead injection steam pressure, the bottom hole heat loss rate continues to increase, and the steam dryness continues to decrease. This research is of great significance for improving the economic benefits of heavy oil production.
... The crude oil within a certain range is heated to reduce its viscosity and be recovered. The injected steam greatly reduces the viscosity of crude oil and improves the flow capacity of crude oil in the oil well, thereby increasing production [23][24][25]. The steam huff and puff oil recovery method is a technology with low investment and simple process. ...
The world's heavy oil resources are very rich, and its geological reserves far exceed conventional crude oil reserves. Steam injection thermal recovery technology is widely used in heavy oil fields around the world, and steam absorption calculation is an important part of steam injection thermal recovery technology. In this paper, the test principle of the high-temperature five-parameter steam absorption profile tester is introduced in detail, and a calculation model for reservoir steam absorption is constructed. Finally, the wells in Kazakhstan have been used for calculation of steam absorption, and the interpretation results have been compared with actual production. The research results show that as the pipeline grows, the heat loss gradually increases, and the dryness decreases to a large extent. When it reaches the wellhead, the dryness is only 57%. This is mainly due to the serious heat loss caused by the excessively long pipeline, which has a great influence on the steam injection effect. The calculation error of the vapor absorption percentage of the oil layer is within 5%, and the calculation result of the vapor absorption percentage is consistent with the on-site interpretation result. The interpretation conclusion verifies the reliability of the method in this paper.
... The geological environment of shale reservoirs and optimized fracturing measures are important guarantees and key external factors for the volumetric fracturing network formation and its full growth, and they directly control the pattern and scale of hydraulic crack [23]. The study of the geologic background such as horizontal principal stress difference and the relationship between natural crack and hydraulic crack can help us to realize the hydraulic crack propagation along the natural crack direction and the transformation into complex fracture network; thus, the stimulated reservoir volume can be improved largely [24,25]. In addition, the morphology of fracture network can also be affected by the fracturing operation factors (volume of fracturing fluid, flow rate, and the spacing between fracturing segments) [26] and fracturing techniques (horizontal well multistage fracturing, synchronous fracturing, zipper fracturing, and refracturing) [27]. ...
Shale gas can be commercially produced using the stimulated reservoir volume (SRV) with multistage fracturing or multiwell synchronous fracturing. These fracturing technologies can produce additional stress fields that significantly influence the crack initiation pressure and the formation of an effective fracture network. Therefore, this study primarily investigated the evolution of crack initiation and propagation in a hydraulic rock mass under various stress conditions. Combining the in situ stress characteristics of a shale reservoir and fracturing technology, three types of true triaxial volumetric fracturing simulation experiments were designed and performed on shale, including three-dimensional constant loading, one-dimensional pressurization disturbance, and one-dimensional depressurization disturbance. The results indicate that the critical failure strength of the shale rock increases as the three-dimensional constant loads are increased. The rupture surface is always parallel to the maximum principal stress plane in both the simulated vertical and horizontal wells. Under the same in situ stress conditions in the wellbore direction, if the lateral pressure becomes larger, the critical failure strength of shale rock would increase. Additionally, when the lateral in situ stress difference coefficient is smaller, the rock specimen has an evident trend to form more complex cracks. When the shale rock was subjected to lateral disturbance loads, the critical failure strength was approximately 10 MPa less than that in the state of constant loading, indicating that the specimen with disturbance loads is more likely to be fractured. Moreover, shale rock under the depressurization disturbance load is more easily fractured compared with the pressurization disturbance. These findings could provide a theoretical basis and technical support for multistage or multiwell synchronous fracturing in shale gas production.
... 103 However, these reservoirs possess unique characteristics that entail special development plans. 104,105 With the most efficient development plan, we recover less than 10% of the hydrocarbons in place. 106,107 To improve the current recovery factors, a fundamental understanding of the shale characteristics is required. ...
Experiments are always the go-to approach to reveal mysterious observations and verify new theories. However, scientific research has shifted to areas that are difficult to probe experimentally. Fortunately, computational approaches, such as molecular simulation, became available. With a rigorous theoretical foundation and microscopic insights, molecular simulation could explore unknown territories in physics and validate macroscopic theories. Grand challenges in petroleum engineering require knowledge at the molecular scale more than ever, such as the behavior of confined fluids in shale nanopores. Although it is widely used in materials science, biophysics, and biochemistry, molecular simulation has been underutilized in subsurface modeling. However, the complexity of the subsurface systems and the heterogeneity of reservoir fluids, which currently challenge both our continuum modeling approaches and experimental techniques, could benefit from molecular insights. In this Review, we briefly present the basics of molecular simulation and a few applications addressing current petroleum engineering challenges. These applications include (1) phase equilibria, where molecular simulation handles inaccessible experimental conditions such as high pressure, high temperature, or a toxic environment; (2) asphaltene aggregation, where molecular simulation enables the synthesis and evaluation of the solvent performance; (3) low-salinity water flooding, where molecular simulation reveals the key mechanisms; and (4) shale reservoirs, where molecular simulation derives the new physics controlling the transport phenomena in these reservoirs. Our goal is to demonstrate that the molecular models can shed some light on numerous subsurface applications, moving toward more predictive physics-based models to optimize and control subsurface systems.
... Hydraulic fracturing is a key technology for stimulating oil and gas wells to increase their productivity. Especially in shale gas production, the ultralow permeability of reservoirs requires a large fracture network to maximize well performance, and hydraulic fracturing has made it possible for commercial production by means of multistage fracturing of horizontal wells (Britt and Schoeffler, 2009;Jang and Lee, 2015;Mayerhofer et al., 2010;Shen et al., 2016Shen et al., , 2018b. Hydraulic fracturing is a typical hydromechanical coupling problem that involves the coupling of at least three processes (Adachi et al., 2007): rock mass deformation under the effect of fluid pressure, fluid flow within fractures and fracture propagation. ...
Hydraulic fracturing is one of the most important technologies for shale gas production. Complex hydraulic fracture networks can be stimulated in shale reservoirs due to the existence of numerous natural fractures. The prediction of the complex fracture network remains a difficult and challenging problem. This paper presents a fully coupled hydromechanical model for complex hydraulic fracture network propagation based on the discontinuous deformation analysis (DDA) method. In the proposed model, the fracture propagation and rock mass deformation are simulated under the framework of DDA, and the fluid flow within fractures is simulated using lubrication theory. In particular, the natural fracture network is considered by using the discrete fracture network (DFN) model. The proposed model is widely verified against several analytical and experimental results. All the numerical results show good agreement. Then, this model is applied to field-scale modeling of hydraulic fracturing in naturally fractured shale reservoirs. The simulation results show that the proposed model can capture the evolution process of complex hydraulic fracture networks. This work offers a feasible numerical tool for investigating hydraulic fracturing processes, which may be useful for optimizing the fracturing design of shale gas reservoirs.
... Moreover, fracture network within the shale reservoir (natural and induced fractures) is the major contributor to production [16]. Also, fracture initiation and propagation are well explained by ductile/brittleness regimes within shale [17]. ...
The lower Silurian Qusaiba Shale is one of the major source rocks for Paleozoic oil/gas reservoirs in Saudi Arabia and recently considered a potential unconventional shale gas resource. The study aims to evaluate the reservoir heterogeneity and production potential of Qusaiba Shale through the integration of geological, geomechanical and fractures characteristics. Three lithofacies were identified in Qusaiba shale. Mineralogical composition resulted in variable amounts of quartz ranging from 39 to 40, 45–55 and 60–78% for Lithofacies-I, II and III, respectively. Inter-granular porosity of these lithofacies is very low; however, fractures along laminations, at angle with laminations, and few micro-faults enhance porosity up to 5–6, 2–3, and < 1% in Lithofacies-I, II and III, respectively. The Lithofacies-I hosts the lowest fracture density (1.2 fractures/foot), likely due to the relatively lower quartz content (39%) as compared to other lithofacies. The fracture densities in Lithofacies-II and III are 2.1 and 3.2 fractures/foot, respectively. Lithofacies-I exhibits low stiffness in terms of low Young’s modulus (average 26 GPa) and high Poisson’s ratio (average 0.34). Mineralogy- and elastic parameters-based brittleness indices exhibited ductile behavior of this lithofacies. The brittleness index exhibited brittle behavior for silica-rich Lithofacies-III and has highest intensity of natural fractures. Hence, it is concluded that mineralogy and geological characteristics are the main controlling factors on shale brittleness, mechanical properties and fractures characteristics. The integration of geology, mineralogy and geomechanics plays the key role to better evaluate the prospectivity of shale reservoirs.
... Many researchers have considered this source rock to also be a prospective unconventional reservoir as the average total organic carbon (TOC) is higher than 2%, hosting just over 60,000 barrels of crude oil production (Archie, 2018;Persad et al., 1993;Requejo et al., 1994;Rodrigues, 1988). Unconventional reservoirs are usually described as reservoirs with less than 10% matrix porosity and less than 0.1 mD (10 −17 m 2 ) matrix permeability (Law and Spencer, 1993;Neuzil, 1994) and can only produce at commercial rates with stimulation of the reservoir (Bhattacharya and Nikolaou, 2011;Britt and Schoeffler, 2009;Eshkalak et al., 2014). These reservoirs include tight-gas sands and gas or oil shale that are difficult to produce by conventional methods. ...
The late Cretaceous Naparima Hill Formation is a prolific oil source rock of the SE Caribbean, with its northern South
America (Venezuela and Colombia) equivalent being the La Luna Formation. The late Cretaceous Naparima Hill Formation
generates most of the crude oils produced from the Southern and Columbus Basins Trinidad, accumulated in
Tertiary fluvial-deltaic sand reservoirs. With the total organic carbon (TOC) of this formation being >2% and crude oil
produced from the Naparima Hill Formation, many researchers have considered this formation to also be a prospective
unconventional reservoir (‘source rock reservoir’). Understanding the Geomechanical properties and lithofacies
is essential for effective exploitation of these unconventional reservoirs. Outcrop samples of the Naparima Hill Formation
were collected along the northern flank of the southernmost surface expression of the Central Range uplift
approximately 10 km north of the prolific Southern Basin. Petrographical analysis was carried out on 11 sample
locations by way of X-Ray Diffraction, optical microscopy and scanning electron microscope. Results revealed many
lithofacies within the Naparima Hill Formation, mainly siliceous mudstones, with very few samples being calcareous
with low clay content and occasional Foraminiferal tests filled with calcite and commonly filled with oil. Most
samples show a textural relationship between organic matter and inorganic minerals. Post- deposition alteration is
characterized by mineral dissolution, veining and high-density microfractures.
Permeability, P- and S-wave velocity, and porosity measurements were carried out on the 11 sample locations at
room temperature to characterize the Naparima Hill formation. We measured the permeability and the velocity using
the transient pulse decay technique and through-transmission method respectively, on fluid-saturated samples
at effective pressures up to 130 MPa. Permeability, P-wave and S-wave velocity results range from 10-3 to 10-5 mD ,
2558 to 4951 m/s and 1372 to 2891 m/s respectively, with no significant change with effective pressure. The porosity
was measured using gas expansion method at atmospheric pressure condition. The porosity values range from 5 to
30%. The study revealed that mineral composition, microfractures, lithofacies and diagenesis play an important role
in understanding the mechanical behaviour of the Naparima Hill Formation.
Uwaila Charles Iyare, Oshaine Omar Blake, Ryan Ramsook
The University of the West Indies, St. Augustine Campus, Trinidad and Tobago
SESSION 3: Laboratory fracture and rock characterization studies
Contact: Uwaila
... Unconventional hydrocarbon reservoirs such as shale-gas and shale-oil are constituted by rocks with a high content of organic matter (TOC> 2%), thermal maturity in the oil/gas window, fragile (quartz content> 40% and clay content <40%) and capable of producing commercially significant amounts of hydrocarbons with extensive fracture (Jarvie et al., 2007;Britt and Schoeffler, 2009;Binnion, 2012). Barnett Shale is a classic example of a shale-type reservoir, giving the best production from areas with 45% quartz and only 27% clays (Bowker, 2007), although the content of clays, quartz, and carbonates is highly variable and these differences result in variable fracture gradients (Bowker, 2007). ...
The objective of this work is to discuss the paleoenvironment and age of the Los Monos Formation, in outcrop and subsurface, along a regional transect (west-east) in the southern sector of the Tarija basin. The lithofacies and ichnofacies of the Alarache, Angosto del Pescado and Balapuca outcrops and core-intervals of the Aguas Blancas xp-13, Ramos x-12, Tartagal x-1 and Tonono x-1 boreholes were analyzed. The definition of lithofacies and ichnofacies allowed us to interpret a shallow to outer shelf paleoenvironment (from the offshore-transition, offshore and shelf). Towards the top of the Tonono Formation, the equivalent of the Los Monos Formation in the Chaco-Salteño was defined as a brackish-waters marginal-marine paleoenvironment. The mineralogy of the mentioned sections plus the Vespucio x-1 borehole was analyzed by X-ray diffraction (XRD) and scanning electron microscopy (SEM), thus the majority elements in clay minerals were also determined from EDAX. Authigenic and detrital clays from SEM-EDAX were recognized. Four clay mineral assemblages were defined (I+Ch; Ch+I; I+K; K+I), where I+K and K+I assemblages characterize the transgressive events within the basin. The palynofacies of the Balapuca, Alarache and Angosto del Pescado outcrops and samples from the Ramos xp-1002, Ramos xp-1011 and Ramos xp-1012 boreholes were defined, the dominance of terrestrial palynomorphs was identified with variable participation of marine palynomorphs, according to a shallow marine paleoenvironment with shoreline shifts. Two transgressive events were recognized during the late Eifelian-early Givetian and the late Givetian-early Frasnian, which are characterized by an increase in marine components and clay assemblages of I+K and K+I. The palynological associations point to a late Eifelian-early to middle Givetian age for the Los Monos Formation in the study area. The analysis of illite crystallinity and expansive layers in the mixed-layer IS indicated advanced diagenesis for the unit, from late mesodiagenesis (Tonono x-1 and Vespucio x-1) to telodiagenesis (Balapuca and Ramos), according to the final stage of oil generation window to gas generation window, respectively. Finally, based on the mineral composition with a predominance of quartz (>70% in average) and low content of clays (<20% in average), thermal maturity in oil and gas window, the important thickness in the subsurface (700-1000 meters) and significant lateral continuity (>100 km2), the unit has some of the attributes to be considered as a potential shale-type unconventional reservoir.
... Rickman R. [4], show integrated mineralogy and geomechanics with petrophysics to optimize fracture program design and concluded that not all shales are the same, describe mineralogical (clay content) and geomechanical conditions required on an excellent shale gas play. Britt, L.K. [5], they recommended adopting mineralogical and static elastic cutoffs, below which shales were not considered prospective from a brittle fracturing perspective. Hydraulic fracturing is more effective in the zone of brittle lithology, called the sweet spot. ...
... When the static Young's modulus is generally in excess of 3.5 × 10 6 psi (about 24.1 GPa), shale tends to be brittle, and the brittleness is associated with the shale's complete lack of clay mineral content. 12 However, brittleness cannot be estimated from the fraction of individual clay contents; rather, it depends on the proportion of each of the mineral components of the shale. 8,13,14 When confining pressure increases, rock failure types gradually change from brittle to ductile. ...
The brittle failure of Chengkou shale occurs throughout the exploration and development processes of hydrocarbons. To investigate the failure mechanisms of Chengkou shale and analyze the associated mechanical behavior such as crack initiation, propagation, and coalescence at different stress levels, a series of laboratory experiments were conducted on servo-controlled triaxial cells equipped with ultrasound monitoring. The experimental results show that key mechanical parameters such as peak stress σp, stress onset of dilation σci, and strain at peak stress εp exhibit nearly linear relationships at various confining pressures. In rock bodies, the wave velocity evolution at different stress levels very consistently reproduces the shape of stress–strain curves, while shear wave velocity vs is more sensitive to crack damage than compressional wave velocity vp. Furthermore, the Hoek–Brown failure criterion has an advantage over the Mohr–Coulomb fracture criterion due to the former’s higher correlation coefficient r². The wing crack damage models with sandwiched multilayers help explain the mixed tensile and shear failure mechanisms of Chengkou shale. The experimental results provide significant guidance for optimizing the design of drilling and well completion jobs, especially hydraulic fracturing operations, both in Chengkou shale and in other brittle shales around the world.
... This heterogeneity is exhibited at a variety of scales, including reservoir-, core-, and pore-scale, which adds to the complexity of shales and presents a serious challenge in quantifying their petrophysical and geomechanical properties (Goral et al., 2015a(Goral et al., ,b, 2017(Goral et al., , 2018(Goral et al., , 2019a(Goral et al., , b,c, 2020Suarez-Rivera et al., 2005). These properties are essential for proper hydraulic fracturing design and optimization of shale oil and gas wells (Britt and Schoeffler, 2009;Ganpule et al., 2016;Goral and Miskovic, 2015;Higgins-Borchardt et al., 2016;Krzaczek et al., 2019;Liu et al., 2018;Xia et al., 2017, 2020Zhu et al., 2018a. ...
In this study, macro- and micro-geomechanical properties of shales were investigated at millimeter- and micrometer-scale using an example of the Woodford Shale. Geomechanical properties, such as uniaxial (unconfined) compressive strength and Young's modulus, were quantified at the millimeter-scale and compared with results from micro-compression testing experiments of FIB-SEM-nanofabricated micro-pillars. Size-scale and compositional/structural heterogeneity effect on elasto-plastic deformation and failure behavior of shales were investigated. Also, relationship between elemental/mineral composition and unconfined compressive strength and Young's modulus, at a micrometer-scale, was discussed. It was shown that geomechanical properties of shales are scale-dependent and are strongly affected by compositional/structural anisotropy. In particular, micro-compression testing experiments showed non-uniformly distributed compressive strength and Young's modulus within the investigated Woodford Shale rock samples. It was demonstrated, that geomechanical properties of shales, investigated at the micrometer-scale, tend to be affected by different minerals and/or pores, while the same properties, investigated at the millimeter-scale, are governed by different micro-facies (and/or micro-fractures) present within the rock. This shows that geomechanical properties of shales can be dramatically different depending on the scale of investigation and compositional/structural heterogeneity of these rocks, and therefore are not easily transferable across the scales.
... The shape of SRV can be predicted from stimulated and shear propped fractures, while the volume can be correlated with fracture network length. Britt et al. 2008& Cipollaet et al. 2008 discussed geomechanics of a shale prospective and fracture complexity. ...
This chapter contains sections titled: Introduction Problem Definition and Modeling Development of a New Mathematical Model Model Building Results and Discussions Conclusions and Recommendations
... In contrast, a ductile shale reservoir deforms plastically and can undergo significant strain before fracturing. Therefore, it absorbs more energy while breaking, hence reducing the net effect of the hydraulic fracturing operation [33,114,134,103]. Additionally, brittleness influences the propagation of natural fractures that ultimately control the availability of extractable HCs [65,135]. ...
The advent and advancement in hydraulic fracturing techniques have resulted in the rapid growth of unconventional shale oil and gas production over the last couple of decades. Unlike conventional hydrocarbon systems, these shale formations serve as both the source and reservoir and therefore are directly drilled into for hydrocarbon production. Studies in different shale basins have revealed that these reservoirs are geologically complex, heterogeneous, and every play is unique. Therefore, for efficient hydrocarbon recovery, physicochemical, and mechanical attributes of individual shale reservoir need to be taken into account. Even after significant technological advancements, we are still struggling to understand the spatiotemporal variations in type and amount of hydrocarbon produced within a single basin, rapid declines in hydrocarbon production, and the low fracturing fluid recovery rates. In this review article, we briefly summarize how biogeochemical tools can be used to 1) understand variations in the quantity of organic matter (OM) that ultimately controls production of hydrocarbon, 2) determine variations in the quality of OM that ultimately controls the quality and type of hydrocarbons generated, 3) predict the fracturing potential of rock, and 4) increase efficiency of hydrocarbon production by controlling the water-rock-microbe interactions that ensue after hydraulic fracturing fluids are injected into the shale reservoirs. A better understanding and utilization of these biogeochemical processes and tools will help identify sweet spots for shale gas drilling, increase hydrocarbon recovery and open up the possibility of engineering the hydraulic fracturing fluids to enhance recovery and life of these shale reservoirs.
... The static Young moduli measured on two middle Velkerri samples yielded values of 23 and 34 GPa (Revie, 2017). Based on historical data, prospective shales have a static Young's modulus in excess of 24.1 GPa (Britt and Schoeffler, 2009). The measured static Poisson's ratios of these two samples were also 0.10 and 0.31 displaying inconsistency within the middle Velkerri Formation, however, there are inadequate samples to reflect on the general character of the unit (Revie, 2017). ...
Despite extensive research conducted on North American and Chinese shale plays, fairly little has been reported on Australian gas-shales and no comparative study exists to assess their complexity associated with their geological setting and mineralogical compositions. We thus performed an extensive set of petrophysical characterizations including mineralogy, porosity, permeability, pore size distribution, fracture system, wettability, adsorption capacity, and mechanical properties of four organic-rich shale formations from across some of the major Australian sedimentary basins (Beetaloo, Perth, and Cooper).
The results of the petrophysical characterisations reveal that the middle Velkerri formation from Beetaloo basin has the highest potential for future development amongst formations studied in these three basins. Generally, a) the samples show consistent water wet contact angles despite having fairly different TOC, b) the uniaxial compressive strength is not correlated to the amount of clay content of the samples and c) a positive correlation is observed between the Quartz content and TOC.
... Moreover, fracture network within the shale reservoir (natural and induced fractures) is the major contributor to production [16]. Also, fracture initiation and propagation are well explained by ductile/brittleness regimes within shale [17]. ...
The Lower Silurian Qusaiba Shale is main hydrocarbon provider for the Paleozoic petroleum system of Saudi Arabia and considered one of the main targets for unconventional shale gas. The study focuses on the lithofacies and fractures on both macro and micro scale in the Qusaiba Shale in order to better understand the effect of reservoir heterogeneity on fractures generation. The study was conducted on 30 feet subsurface core samples representing the Qusaiba Shale from the Rub Al-Khali Basin. The type and intensity of fractures were integrated with lithofacies type and mineralogy. Lithofacies were categorized on the basis of geological characteristics on both macro and micro scale. Cores using binocular lens are fully described in terms of color, size, mineralogy, primary sedimentary structures, fractures type and orientation, and diagenetic features. In addition, 30 thin sections were used to determine micro geological features including components of shale, mineralogy, natural fractures, porosity type as well as other micro-scale geological features.
... The latter is poorly investigated so far but expected to be a very prospective shale play (e.g., Smith et al. 2010;Imber et al. 2014;Hough et al. 2014). Here we establish empirical relations between mechanical properties (strength, Young's modulus) and confining pressure, temperature and strain rate, which are important in the petroleum industry (Draege et al. 2006;Farrokhrouz et al. 2014), e.g., for assessment of borehole stability and evaluation of stable mud weight windows for drilling or hydraulic fracturing (Warpinski et al. 2009;Britt and Schoeffler 2009;Soliman et al. 2012;Meier et al. 2013Meier et al. , 2015Gholami et al. 2014). The results are also helpful to correlate with data measured during in situ operations such as wire line well logging (Horsrud 2001;Chang et al. 2006 Rybacki et al. 2015). ...
The thesis comprises three experimental studies, which were carried out to unravel the short- as well as the long-term mechanical properties of shale rocks. Short-term mechanical properties such as compressive strength and Young’s modulus were taken from recorded stress-strain curves of constant strain rate tests. Long-term mechanical properties are represented by the time– dependent creep behavior of shales. This was obtained from constant stress experiments, where the test duration ranged from a couple minutes up to two weeks. A profound knowledge of the mechanical behavior of shales is crucial to reliably estimate the potential of a shale reservoir for an economical and sustainable extraction of hydrocarbons (HC). In addition, healing of clay-rich forming cap rocks involving creep and compaction is important for underground storage of carbon dioxide and nuclear waste. Chapter 1 introduces general aspects of the research topic at hand and highlights the motivation for conducting this study. At present, a shift from energy recovered from conventional resources e.g., coal towards energy provided by renewable resources such as wind or water is a big challenge. Gas recovered from unconventional reservoirs (shale plays) is considered a potential bridge technology. In Chapter 2, short-term mechanical properties of two European mature shale rocks are presented, which were determined from constant strain rate experiments performed at ambient and in situ deformation conditions (confining pressure, pc ≤ 100 MPa, temperature, T ≤ 125 °C, representing pc, T - conditions at < 4 km depth) using a Paterson– type gas deformation apparatus. The investigated shales were mainly from drill core material of Posidonia (Germany) shale and weathered material of Bowland (United Kingdom) shale. The results are compared with mechanical properties of North American shales. Triaxial compression tests performed perpendicular to bedding revealed semibrittle deformation behavior of Posidonia shale with pronounced inelastic deformation. This is in contrast to Bowland shale samples that deformed brittle and displayed predominantly elastic deformation. The static Young’s modulus, E, and triaxial compressive strength, σTCS, determined from recorded stress-strain curves strongly depended on the applied confining pressure and sample composition, whereas the influence of temperature and strain rate on E and σTCS was minor. Shales with larger amounts of weak minerals (clay, mica, total organic carbon) yielded decreasing E and σTCS. This may be related to a shift from deformation supported by a load-bearing framework of hard phases (e.g., quartz) towards deformation of interconnected weak minerals, particularly for higher fractions of about 25 – 30 vol% weak phases. Comparing mechanical properties determined at reservoir conditions with mechanical data applying effective medium theories revealed that E and σTCS of Posidonia and Bowland shale are close to the lower (Reuss) bound. Brittleness B is often quoted as a measure indicating the response of a shale formation to stimulation and economic production. The brittleness, B, of Posidonia and Bowland shale, estimated from E, is in good agreement with the experimental results. This correlation may be useful to predict B from sonic logs, from which the (dynamic) Young’s modulus can be retrieved. Chapter 3 presents a study of the long-term creep properties of an immature Posidonia shale. Constant stress experiments (σ = const.) were performed at elevated confining pressures (pc = 50 – 200 MPa) and temperatures (T = 50 – 200 °C) to simulate reservoir pc, T - conditions. The Posidonia shale samples were acquired from a quarry in South Germany. At stresses below ≈ 84 % compressive strength of Posidonia shale, at high temperature and low confining pressure, samples showed pronounced transient (primary) creep with high deformation rates in the semibrittle regime. Sample deformation was mainly accommodated by creep of weak sample constituents and pore space reduction. An empirical power law relation between strain and time, which also accounts for the influence of pc, T and σ on creep strain was formulated to describe the primary creep phase. Extrapolation of the results to a creep period of several years, which is the typical time interval for a large production decline, suggest that fracture closure is unlikely at low stresses. At high stresses as expected for example at the contact between the fracture surfaces and proppants added during stimulation measures, subcritical crack growth may lead to secondary and tertiary creep. An empirical power law is suggested to describe secondary creep of shale rocks as a function of stress, pressure and temperature. The predicted closure rates agree with typical production decline curves recorded during the extraction of hydrocarbons. At the investigated conditions, the creep behavior of Posidonia shale was found to correlate with brittleness, calculated from sample composition. In Chapter 4 the creep properties of mature Posidonia and Bowland shales are presented. The observed long-term creep behavior is compared to the short-term behavior determined in Chapter 2. Creep experiments were performed at simulated reservoir conditions of pc = 50 – 115 MPa and T = 75 – 150 °C. Similar to the mechanical response of immature Posidonia shale samples investigated in Chapter 3, creep strain rates of mature Bowland and Posidonia shales were enhanced with increasing stress and temperature and decreasing confining pressures. Depending on applied deformation conditions, samples displayed either only a primary (decelerating) or in addition also a secondary (quasi-steady state) and subsequently a tertiary (accelerating) creep phase before failure. At the same deformation conditions, creep strain of Posidonia shale, which is rich in weak constituents, is tremendously higher than of quartz-rich Bowland shale. Typically, primary creep strain is again mostly accommodated by deformation of weak minerals and local pore space reduction. At the onset of tertiary creep most of the deformation was accommodated by micro crack growth. A power law was used to characterize the primary creep phase of Posidonia and Bowland shale. Primary creep strain of shale rocks is inversely correlated to triaxial compressive strength and brittleness, as described in Chapter 2. Chapter 5 provides a synthesis of the experimental findings and summarizes the major results of the studies presented in Chapters 2 – 4 and potential applications in the Exploration & Production industry. Chapter 6 gives a brief outlook on potential future experimental research that would help to further improve our understanding of processes leading to fracture closure involving proppant embedment in unconventional shale gas reservoirs. Such insights may allow to improve stimulation techniques aimed at maintaining economical extraction of hydrocarbons over several years.
... Geomaterial chips have the advantage of mimicking the chemical and physical properties of natural porous media. This is of importance, particularly for unconventional reservoirs, due to their heterogeneity, unique fracture system and specific mechanisms such as swelling and shrinkage, which affects flow and transport (Britt and Schoeffler 2009;Liu et al. 2017). Gerami et al. (2017) used an image of a coal fracture obtained from micro-computed tomography (micro-CT) for fabrication of a coal geomaterial microfluidic chip. ...
No matter how sophisticated the structures are and on what length scale the pore sizes are, fluid displacement in porous media can be visualized, captured, mimicked and optimized using microfluidics. Visualizing transport processes is fundamental to our understanding of complex hydrogeological systems, petroleum production, medical science applications and other engineering applications. Microfluidics is an ideal tool for visual observation of flow at high temporal and spatial resolution. Experiments are typically fast, as sample volume is substantially low with the use of miniaturized devices. This review first discusses the fabrication techniques for generating microfluidics devices, experimental setups and new advances in microfluidic fabrication using three-dimensional printing, geomaterials and biomaterials. We then address multiphase transport in subsurface porous media, with an emphasis on hydrology and petroleum engineering applications in the past few decades. We also cover the application of microfluidics to study membrane systems in biomedical science and particle sorting. Lastly, we explore how synergies across different disciplines can lead to innovations in this field. A number of problems that have been resolved, topics that are under investigation and cutting-edge applications that are emerging are highlighted.
... The latter is poorly investigated so far but expected to be a very prospective shale play, (Smith et al. 2010;Imber et al. 2014;Hough et al. 2014). Here we establish empirical relations between mechanical properties (strength, Young's modulus) and confining pressure, temperature and strain rate, which are important in the petroleum industry (Draege et al. 2006;Farrokhrouz et al. 2014) for assessment of borehole stability and evaluation of stable mud weight windows for drilling or hydraulic fracturing (Warpinski et al. 2009;Britt and Schoeffler 2009;Soliman et al. 2012;Meier et al. 2013Meier et al. , 2015Gholami et al. 2014). The results are also helpful to correlate with data measured during in situ operations such as wire line well logging (Horsrud 2001;Chang et al. 2006). ...
The production of hydrocarbons from unconventional reservoirs, like tight shale plays, increased tremendously over the past decade. Hydraulic fracturing is a commonly applied method to increase the productivity of a well drilled in these reservoirs. Unfortunately, the production rate decreases over time presumably due to fracture closure. The fracture closure rate induced by proppant crushing and embedment depends on mechanical properties of shales and proppants that are influenced by confining pressure (pc), temperature (T), and shale composition. We performed constant strain rate deformation tests at ambient and in situ conditions of a typical shale reservoir (pc ≤ 100 MPa, T ≤ 125 °C) using European shale samples exhibiting variable mineralogy, porosity and maturity. We focused on a comparison of Posidonia shale with Bowland shale, which is believed to be the most prospective shale formation in the United Kingdom. Compression tests were performed perpendicular to bedding orientation. Stress–strain curves show that Bowland shales are relatively strong and brittle compared to Posidonia shale which display semibrittle deformation behavior. Brittleness estimated from elastic properties is in good agreement with the recorded stress–strain behavior but shows no clear relation to composition. Compressive strengths (σUCS = uniaxial compressive strength, σTCS = triaxial compressive strength) and static Young’s moduli, E, reveal a strong confining pressure and mineralogy dependence, whereas temperature and strain rate only have a minor influence on σTCS and E. The coefficient of internal friction for both shales is ≈ 0.42 ± 0.03. With increasing amount of weak minerals (e.g., clay, mica) σUCS, σTCS and E strongly decrease. This may be related to a shift from deformation supported by a load-bearing framework of hard minerals to deformation of interconnected weak minerals at about 25–30 vol% of weak phases. At the applied conditions, the triaxial compressive strength and Young’s moduli of most shales deformed normal to bedding are close to the Reuss bound. To our knowledge, this is the first study, which presents results of experimental investigations carried out to characterize the mechanical behavior of Bowland shale. The observed results are helpful to estimate the potential of the Bowland reservoir with respect to the economical extraction of hydrocarbons.
Dynamic material constants obtained by wave-based methods are different from their static counterparts. Constraining rock's elastic constants’ dynamic-to-static ratios (Rij) are important for understanding the geomechanical properties of earth's materials, particularly in the context of hydraulic fracturing that requires the knowledge of shale's static elastic constants. Conducting experiments with dynamic and elastic constants’ anisotropy, on top of their pressure dependency, properly accounted for is challenging. Here, we measure suites of dynamic and static elastic constants, with anisotropy fully accounted for, on the shale samples extracted from the Duvernay unconventional reservoir; a comprehensive set of geochemical/petrophysical measurements are obtained too. We observe that the dynamic-to-static ratios are generally not sensitive to the increasing pressures at σ > 50 MPa; we do not find a correlation with the samples’ mineral contents either. However, we find that Rij strongly correlates to the dynamic elastic constants except for the R11. The correlation between Rij, particularly Ri3, and the dynamic elastic constants can be explained by the sedimentary rocks’ compactness and the horizontal void spaces parallel to the rock's laminated bedding planes.
Shale is often required to act as a natural barrier to fluid flow around nuclear waste repositories and above CO 2 storage sites. The small pore size of the shale matrix makes it an effective barrier to fluid flow. However, leakage could occur along faults or fractures. Experiments provide insight into fault/fracture-related leakage on short timescales (i.e. 1-10 years) compared to that needed for safe disposal (up to 1 Ma). Data collected by the petroleum industry provides strong evidence on how faults and fractures in shale impact fluid flow on such timescales. Faulted shales act as seals to petroleum reservoirs and abnormal pressures on geological timescales (>10 Ma). This observation suggests that faults in shale can either form without acting as flow conduits or act as temporary conduits but then reseal. Index properties such as clay content and elastic moduli are useful for identifying shales in which faults/fractures are likely to self-seal. However, fault and fracture-related fluid flow can occur through weak shales if high overpressures are maintained. Nuclear waste repositories can be sited away from where overpressures could develop. Leakage from CO 2 storage sites is more risky because the CO 2 provides drive to maintain high pressures, which could suppress self-sealing.
Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022
Platform well fracturing is essential for the efficient development of unconventional oil and gas (UOG), and it has been widely applied in oilfields. Field practices have revealed that various fracturing methods result in different stimulation performances, but the mechanisms responsible for these differences are not completely understood. To explore the characteristics of the inter-well stress interference of various platform well fracturing methods, a numerical model was established for the systematic assessment of the stress field of simultaneous fracturing, zipper fracturing (ZF), modified zipper fracturing, and synergic fracturing (SF). Based on these analyses, balanced stress fracturing (BSF) has been proposed to significantly reduce the horizontal stress difference. This study indicates that the fracturing methods significantly impact the evolution of induced stress, and that ZF and SF can achieve a balanced stress field and the utilization of an inter-well reservoir through a reasonable fracture distribution mode and fracturing operation. Combined with the interlaced fracture distribution mode, interactive fracturing, and overall front parallel fracturing, BSF can improve the fracture network complexity (FNC) and reduce the risk of casing deformation. Moreover, BSF helps achieve higher production and a more uniform stress field in platform well fracturing. This study presents an effective measure to increase FNC and reduce the occurrence of casing deformation during UOG development.
With an author team of 26 subject-matter experts representing a diversity of talent, background, and experience, Hydraulic Fracturing: Fundamentals and Advancements delivers a comprehensive discussion on the principles of hydraulic fracturing while also including the latest processes that have prompted the explosive growth in stimulating horizontal wells in shale and tight oil and gas reservoirs.
Brittleness Index (BI) of rocks can help target the most suitable formation for the hydraulic fracturing stimulation in the tight shale reservoirs. The two most widely used approaches in the petroleum industry are based on mineralogical composition and elastic parameters for the BI estimation. However, these approaches may not be applied for all wells for BI determination due to the scarcity of mineralogical-composition and shear wave slowness data.
This paper presents a machine learning (ML) approach to predict the BI using readily available well logs. Well log data were collected from three different wells that encompass a total of 2000 ft thick interval of potential shale gas formation in one of the middle eastern basins. Mineralogical composition of shale formation revealed that the shale intervals are comprising of alternate high brittle and low brittle zones and mainly composed of quartz, clay, feldspar, and mica. Feed-forward artificial neural network (ANN) and Adaptive Neuro-Fuzzy Inference System (ANFIS) were employed to develop the predictive model for the BI.
The proposed model was tested and validated to check the consistency of the model. The reliability of the proposed AI model was reflected by the correlation coefficient (CC) ‘0.97’ between predicted and actual brittleness indices. The root mean squared ‘RMSE’ and average absolute percentage error ‘AAPE’ of the predicted brittleness were observed as 3.78 percent and 1.98 respectively for the ANN model. AAPE and RMSE for ANFIS predictive model were 3.51 and 1.81 respectively. The coefficient of determinations (R2) for ANN and ANFIS models were 0.945 and 0.951 respectively.ANN was found to be better than ANFIS by giving high accuracy. The proposed model was then compared with widely used models in the industry such as Jarvie et al., (2007) and Rybacki et al., (2016) on a blind dataset.
The predictive model was also validated by comparing with two widely used mineralogy-based approaches. The developed approach can be applied to identify the brittle layers/zones within the shale gas reservoirs to optimize the hydraulic fracturing stimulation treatment. Results showed that the proposed model outperformed previous models by giving less error.
Adsorption characteristics of CO2–CH4–H2O-coal matrix systems are extremely important for investigating geological CO2-storage and enhanced coalbed methane recovery. To study the adsorption mechanism of CH4 and CO2 under the equilibrium water state, this study conducted high-pressure mercury intrusion porosimetry, low-temperature N2 adsorption, and high-pressure methane isothermal adsorption of CH4 and CO2 on coal samples under equilibrium water condition. From these experimental results, the parameters including Gibbs free energy change (ΔG), entropy change (ΔS), maximum adsorption volume, selectivity coefficient (α) and Henry’s constant (KH) were extracted to discuss the influence of moisture on the CH4 and CO2 adsorption behavior of low-rank coals. The results show that water in low-rank coal had an “inhibitory effect” on the adsorption of CH4 and CO2. The maximum theoretical adsorption capacity of CO2 (a2) in each coal sample was greater than that of CH4 (a1), and the absolute value of the CO2 entropy change (ΔS2) was greater than that of the CH4 entropy change (ΔS1), indicating that low coal-rank coals had higher adsorption capacity of CO2 than that of CH4. For the equilibrated-water isothermal adsorption results, the differential adsorption of CH4 and CO2 was due to differences in coal maceral compositions and the development of micro- and meso-pores in different coals. It was concluded that CO2 enhanced coalbed methane technology has better application potential in low-rank coal reservoirs than in medium-to-high rank coal reservoirs.
The unconventional reserves are vital future energy resources and globally augmented interest endeavours the discovery of gas and oil-rich shales. The Kommugudem Formation, Krishna Godavari Basin was evaluated based on sample laboratory and well log studies from six wells deciphering mineralogical and organic geochemical parameters to provide an understanding of hydrocarbon potential and brittleness. Kommugudem Formation constitutes Type III kerogen dominantly with high total organic carbon (TOC) and Tmax indicating the presence of high organic matter. The mean vitrinite reflectance indicates mature to post-mature shale majorly in the gas generation window. Fourier transform infrared spectroscopy functional group investigation revealed the presence of aromatics and aliphatics with a higher degree of abundance owing to higher TOC content. The basic well logs recorded in the studied region are used to estimate the continuous TOC and porosity of the formation and corroborate with laboratory core data. Petrographic, X-ray diffraction, and field emission scanning electron microscopy studies revealed the presence of dominantly siliceous mineral matter with relatively lower clay and carbonates. Organic mudstone classification indicates formation is dominantly silica-dominated lithotype and clay-rich siliceous mudstone. Microfractures and micropores are observed in mineral and organic matter that may act as storage sites for hydrocarbons. Kommugudem Formation on the basis of mineralogy indicates compositional analogy with brittle zones of Barnett Shale Formation. The high mineralogical brittleness index of the Kommugudem Formation indicates good conditions for hydraulic fracturing. The present investigation demonstrates excellent hydrocarbon generation potential and good brittleness in wells A and B while C, D, E, and F have relatively lower potential and may have low gas and oil sources.
While every tight oil play is unique, there are lessons that can be transferred from one play to another to improve the efficiency and pace of production operations and development. These improvements may not fit precisely in every basin or play but generally hold to themes that can be tested against and built upon. Themes such as the quantity of proppant, longer lateral length, or the number of stages can be directly tied to increased productivity. However, there are diminishing returns on these investment activities for which each operator, within a given play, will be required to identify and mitigate against.
This is especially true as the industry steps in and begins developing new tight oil plays. In their nascent stages, these plays may have limited well penetrations and, as a result, limited geological and performance data from which to extrapolate. Pulling together an understanding of where the industry currently resides in terms of how to exploit these resources can provide a boost in terms of working towards greatly improved well completions.
In 2019, the US EIA estimated that nearly 8 million barrels of oil per day were produced from tight oil reservoirs in the United States (US EIA, 2020). This represents over 60% of the domestic crude production, originating from multiple reservoirs in the Permian Basin (TX) as well as the Bakken (MT, ND), Eagle Ford (TX), Niobrara (CO, WY), and Anadarko Basin (OK) formations, among others. As such, there are 1,000s of wells across these numerous tight oil plays that can relate an informative story. To build this story, the interplay of geology, well spacing, lateral length, and stimulation, all critical to economic success, will be explored.
This paper proposes to look back at these mature tight oil (and gas) basins and bring forth an understanding of what lessons can be applied to the emerging Powder River Basin tight oil reservoirs (Mowry and the Turner/Frontier). The authors will delve into the four broad topics of geology, well spacing, lateral length, and stimulation, highlighting case studies to demonstrate those lessons from established tight oil plays that will underpin planned activities at a Field Laboratory Test Site in the southern Powder River Basin.
The Montney Formation is one of the largest unconventional resources in North America covering from southwestern Alberta to northeast British Columbia. The Montney Formation has natural gas, natural gas liquids (NGL) and oil from conventional and unconventional reservoirs. The first multiple fractured horizontal well (MFHW) was drilled in 2005. However, since the first MFHW, different methods were proposed to optimize completion designs in the Montney Formation. Some of the optimized completions utilized the "operational effectiveness" of high-rate slick-water fracture designs while other designs utilized energized fracturing fluids. What has been missing was an integrated methodology that utilizes all available data to improve well stimulation and productivity. The objective of this paper is to present a new methodology for selecting lateral well placement, completion strategy and determination of stimulated reservoir volume (SRV) by integrating available data such as curvature data from 3D seismic, micro-seismic, geo-mechanical data, logs, fracability index, mini-frac test, step-rate test, DFIT analysis, core data, and fracture treatment design to optimize well productivity, hydrocarbon recovery and economics.
The process of developing the hybrid model involved integrating the completions design with compositional reservoir simulator using a two-step process; first, the hydraulic fracture design was calibrated using only the micro-seismic data from the stages that were closest to the geophone/receiver (avoiding location bias or signal-noise ratio issues) in order to develop a reliable fracture geometry model. The calibrated fracture model was used for history matching and re-modeling of all the fracture stages in each well. Fracture geometry and dimensions for each stage were obtained from the calibrated fracture model. Secondly, the compositional reservoir simulators were built using reservoir geology, PVT data, production data and well deviations. Fracture dimensions obtained from the calibrated fracture model were then transferred into the reservoir simulator. Finally, curvature data obtained from 3D seismic was used to predict the location of secondary fissures within the well drainage area, and were then incorporated into the compositional reservoir simulator.
The result from this study shows that the hybrid integrated completion and reservoir model can be used for the selection of optimum lateral placement targeting sweet spots that have secondary fissures and good fracability index to maximize production rates, hydrocarbon recovery and to improve well economics. Additionally, this study presents a new hybrid model for determining a representative stimulated reservoir volume (SRV) with discrete fracture networks that captures secondary fissures, which can then be used for production history matching and forecasting.
The key features of this work that will benefit the petroleum industry are:A new methodology for building calibrated fracture model using micro-seismic survey even if the micro-seismic data is of low quality as a result of location bias or signal-noise ratio issuesExtending the stimulated reservoir volume (SRV) to include secondary fissure contributions to the overall well production and recovery.Use of a discrete fracture network with stress dependent fracture permeability in the compositional reservoir simulator to capture the effects of geomechanical changes during depletion.A comparison of well productivity and EUR derived from a planar fracture model versus discrete fracture network based reservoir models.
The laboratory characterization of tight rocks is essential for reliable rock physics analysis. In this study, combined laboratory experiments and computational calculations were applied to specimens from the Bakken Formation to examine the mechanical properties of the unconventional petroleum resource in different scales. Multistage compressive tests were conducted on core plugs with several loading-unloading cycles under different confining pressures. Microscale mechanical test, nanoindentation, were performed to measure microscale elastic properties. Additionally, a comparative study was included using homogenization upscaling methods to model the modulus of the macro-scale sample from nanoindentation measurements and rock mineralogy, respectively.
Results from the triaxial compressive tests showed nonlinear behavior for all samples and pronounced plastic deformation was observed during loading-unloading cycles when lower confining pressures were employed. Young's modulus increased with confining pressures increasing. The ultrasonic P- and S-wave velocities are sensitive to the changes of confining and differential stresses, which might be due to the open and closure of microcracks. Three mechanical phases can be found from nanoindentation results by deconvolution, and the average microscale Young's modulus obtained from nanoindentation tests showed a positive relationship with the theoretical Voigt and Reuss boundaries. The prediction of Young's modulus from mineral fractionand moduli information indicated a better agreement with laboratory data than the nanoindentation cluster dataset.
The complex propagation behaviours of hydraulic fracture (HF) at bedding planes (BPs) and the produced complicated fracture geometry are essential to enhance the production of shale gas reservoirs. To better understand the complex propagation behaviour of HF at BPs with different bond strengths, the propagation behaviour, including arrest, crossing, and deviation, was identified first from post-fracturing shale specimens. The discontinuous stress and displacement fields on both sides of a BP ahead of an HF were then determined using the numerical simulation method. Finally, three mechanisms—principal stress jump, Cook–Gordon debonding or Poisson effect, and elastic dissimilarity—were explored in detail to interpret the complex propagation behaviour. The results revealed that HF is arrested/deviated only at extremely weakly cemented or fully opened BPs, whereas HF crosses strongly cemented BPs. The high heterogeneity of the BPs in cementing strength is responsible for the complex propagation behaviour of HF. The principal stress jump at a BP is caused by the difference in stiffness between the BP and the rock matrix. The maximum tensile principal stress ahead of the HF cannot be transmitted across the weakly cemented or fully opened BPs, suggesting that the HF cannot cross BPs. The principal stresses may rotate at a weakly cemented BP, and the rotated principal stresses tend to terminate or deviate an HF. Because of Cook–Gordon debonding and the Poisson effect, if a weakly cemented BP is present and is roughly normal to an advancing HF, the BP may break at some distance ahead of the fracture tip and induce a secondary fracture along the BP. The HF then reaches the opened BP and deviates towards the BP. The propagation process of L- or T-shaped fractures can be interpreted both by the Cook–Gordon debonding and Poisson effect from the viewpoints of stress and displacement. The three mechanisms often operate together when an HF deviates towards a weak BP; while for a special case, there may be only one dominant mechanism.
To fully understand the flow mechanisms in oil reservoirs, analysis at pore-scale is required, as it is the length scale at which capillary-trapped oil is mobilized. In particular, analysis at this length scale would help in developing efficient recovery methods to achieve the best possible oil recovery. In this paper, we use a novel geomaterial microfluidics device that couples the surface chemistry and mimics a real sandstone rock to analyze Alkaline Surfactant Polymer (ASP) flooding at the pore scale. An experimental micro-scale approach was developed utilizing geomaterial micromodels for analyzing oil recovery. The geomaterial micromodel is fabricated using soft lithography and polydimethylsiloxane (PDMS) as the main material. Then, to functionalize the PDMS devices, the relevant minerals for sandstone (Quartz and Kaolinite) are added to create the geomaterial micromodel device. To study the effect of minerals presence on oil recovery during ASP flooding, oil recovery is measured using geomaterial microfluidics, as well as plain PDMS microfluidics device that has the same porous media pattern. The results show the different displacement patterns and oil recovery achieved by waterflooding and followed by ASP flooding, which is the typical practice in any enhanced oil recovery method. Results showed oil recovery of 65 % followed by 69 % for waterflood and ASP, respectively in a geomaterial device. In the plain PDMS microfluidics device, an oil recovery of 75 % followed by 80 % for waterflood and ASP, respectively. The geomaterial microfluidics chip provided a more realistic oil recovery values compared to the plain PDMS chip. Therefore, using this novel geomaterial microfluidics fabrication method creates an ideal visualization platform to study the pore scale of any given flood, as it captures the surface chemistry, roughness, and pore networks present in actual rocks. This would ultimately help develop and optimize oil recovery mechanisms.
Quantification of risk to seal integrity in CCS, or gas extraction from hydraulic fracturing, is directly affected by the accessibility of organic pores within organic rich mudrocks. Knowledge of the host organic matter's mechanical properties, which are influenced by depositional environment and thermal maturity, are required to reduce operational risk. In this study we address the effect of both depositional environment and maturity on organic matter Young's modulus by means of Atomic Force Microscopy Quantitative ImagingTM, which is a nondestructive technique capable of nanomechanical measurements. Shales from varying marine depositional environments covering kerogen Types II (Barnett), IIS (Tarfaya), and II/III (Eagle Ford/ Bowland) are analyzed to capture variance in organic matter. The findings show organic matter has a Young's modulus ranging between 0.1 and 24 GPa. These marine shales have a bimodal distribution of Young's modulus to some degree, with peaks at between 3–10 and 19–24 GPa. These shales exhibit a trend with maturity, whereby Young's modulus values of <10 GPa are dominant in immature Tarfaya shale, becoming similar to the proportion of values above 15 GPa within the oil window, before the stiffer values dominate into the gas window. These peaks most likely represent soft heterogeneous aliphatic rich kerogen and stiff ordered aromatic rich kerogen, evidenced by the increase in the stiffer component with maturity and correlated with ¹³C NMR spectrocopy. These findings enable increased realism in microscale geomechanical fracture tip propagation models and may allow direct comparison between Young's modulus and Rock‐Eval parameters.
The Second Member of Kongdian Formation (Ek2) shale oil system is a set of thick organic-rich lacustrine shales with great shale oil resources potential. The shales are oil-prone with high organic matter abundance (samples with TOC > 2% accounting for 72.6%) and low maturity (the Ro of samples between 0.42% and 0.84%). The Ek2 shale system is dominated by shales, sandstones, and carbonate rocks, which can be subdivided into various-mixed lithologies. The shales are primarily composed of clay minerals, quartz, feldspar, calcite, dolomite, pyrite, siderite, and zeolite, with no obvious predominant minerals. The brittle mineral content is high with an average content of 73.86%, which is conducive to reservoir stimulation. Physical properties and oil saturations vary significantly among different lithologies. Tight sandstones (average porosity 8.66%, average permeability 2.207 × 10⁻³ μm²) and dolomites (average porosity 5.26%, average permeability 1.910 × 10⁻³ μm²) have better exploration potential than shales (average porosity 2.46%, average permeability 0.937 × 10⁻³ μm²). Considering Ro distribution, the slope zones are more favorable than Kongdian Structure Belt laterally and the lower intervals of the Ek2 shale are more potential for shale oil accumulation than the upper interval vertically.
Anthropogenic emission of greenhouse gases particularly, CO2 is believed to be responsible for the global climate change. Carbon sequestration has been identified as one of the technological alternatives of reducing CO2 emission from the atmosphere. Disposal of CO2 in unconventional reserves such as shale formations may help in achieving the objectives of sequestration of the CO2 coupled with enhanced recovery of methane. The methane/CO2 storage potential of shale mainly depends on its porous nature which is very complex due to the presence of micro-, meso-, and macro-pores. Understanding the pore size distribution of shales is important because the storage and transport mechanisms of methane and CO2 vary as per the size of the pore. Further, the clay minerals present may also contribute significantly to the adsorption capacity of the shale and may thus control the gas storage. In the present study, an attempt was made to investigate the pore structure of some shale samples from Damodar valley coalfields (Jharia and Raniganj coalfields) in detail and to correlate the pore parameters with adsorption of methane. Secondly, the clay mineral composition of the studied shales was analyzed and its effect on porosity and adsorption were examined. Low pressure nitrogen and carbon dioxide adsorption tests, mercury intrusion and helium pycnometry tests were carried out to ascertain the pore sizes, surface area, and pore volumes. It was observed that the porosity for most of the studied shales were dominated by mesopores. A moderate correlation was observed between nitrogen BET surface area and porosity suggesting lesser amount of micropores and dominance of mesopores. Porosity of the studied shales varied with the clay mineral content exhibiting a U-shaped relationship.
In this paper equations and methodologies for the simple modeling of gas flow in fractured shale are developed. Transmissibility following hydraulic fracturing is related to the geo-mechanical properties of the shale. Methods for the application of these models using commercial conventional reservoir models to predict well productivity are developed. This provides a valuable tool in estimating the productivity and economic value of a potential shale gas play where only geological, petrophysical and geo-mechanical and limited or analogue production data is available.
To better understand the non-planar propagation and geometry of fracture networks, hydraulic fracturing simulation tests on shale specimens were conducted using an established true triaxial hydraulic fracturing simulation test system. A two-dimensional numerical model of hydraulic fracturing was developed to clarify the evolution of hydraulic fractures and their non-planar behaviour at bedding planes. The numerical model with the alternating rock matrix and bedding planes considered the coupling effect of stress, fluid flow, and damage. The mechanisms by which hydraulic fractures penetrate or become arrested/deflected at bedding planes were then revealed as per the physical and numerical simulation results. The results revealed that the typical severe fluctuation of the injection pressure, which is closely related to the growth of sub-fractures along bedding planes or natural fractures, is a clear characteristic of the non-planar propagation of hydraulic fractures. The mechanical properties of the bedding primarily determine whether a hydraulic fracture penetrates or is deflected at the bedding. Strong beddings favour hydraulic fracture penetration; whereas, weak beddings favour hydraulic fracture deflection along the beddings. The hydraulic fractures typically extend along the path of least resistance, and therefore, induce the non-planar propagation behaviour at bedding planes. Tensile failure is a major fracture mechanism of the hydraulic fractures that penetrate or deviate at bedding planes. The experimental and numerical findings provide a basis for the optimum design of hydraulic fracturing and control of the fracture growth geometry in shale gas reservoirs.
Low-temperature nitrogen and isothermal adsorption experiments were conducted on six typical low-rank coal samples from the Fukang mining area, Xinjiang, PR China. Using different temperatures, the effects of the coal's pore structure on gas adsorption and other thermodynamic characteristics were analyzed. The Clausius–Clapeyron equation was used to calculate the isosteric heat of adsorption, and the standard adsorption equilibrium constant was derived to calculate the adsorption free-energy and entropy. The relationships between pore structure characteristics and gas adsorption thermodynamic parameters were investigated. The results showed that the adsorption free-energy and enthalpy of the coal samples decreased with an increase in temperature. Adsorption heat and adsorption entropy were affected by an increase in pore volume and specific surface area. The specific surface area and transition pore volume exhibited quadratic relationships with the free-energy and total pore volume, whereas the mesopore volume exhibited a positive linear relationship with the adsorption free-energy. No prominent relationships among average pore diameter, adsorption heat, adsorption free-energy, and adsorption entropy were observed. No correlation was identified between micropore volume and adsorption free-energy. Fractal dimension was linearly and positively related to the adsorption heat and entropy but had no effect on the free-energy.
Horizontal drilling and multistage hydraulic fracturing applied in tight reservoirs in North America over the past decade and economic productivity attained by creating large fracture surface area to contact the reservoir and create the conductive pathway for the flow of hydrocarbon into the wellbore. Perforation cluster spacing and fracture stagging are keys to successful hydraulic fracturing treatment for horizontal wells. The early focus of the industry was on the operational efficiency. A geometric spacing of perforation clusters adopted as the preferred completion method. Cipolla (2011) presented a case study on the interpretation of production logs from hundreds of horizontal wells. The results indicated that 60% of perforation clusters contribute to production when completed geometrically. Recently, numerous studies have been undertaken to understand this phenomenon. Increasing the stimulation effectiveness and maximizing the number of perforation clusters contributing to productivity was an obvious area for improvement to engineering the completion design. An area with a limited number of horizontally multistage fractured appraisal wells in the Western Desert of Egypt is targeted for this study. The developed workflow comprises integration of petrophysical, geomechanical and production data analysis to evaluate reservoir and completion qualities and quantify the heterogeneity and selectively place perforation clusters in "like-rock" thus promoting the chance of initiating all perforation clusters within a stage and ensuring uniform placement and distribution of the induced fractures and that every cluster in each zone is fracture stimulated and can contribute to the well's full potential. The hydraulic fracture attributes from the fracture simulator were exported to the reservoir simulator. The surface production measurement together with the production profile was used to calibrate the reservoir model.
The scope of this study is to present an integrated workflow to identify reservoir properties variation along the lateral section of horizontal to engineer completion design, improve stimulation effectiveness, and improve cluster efficiency. The methodology adopted in this study resulted in optimized fracture design that helped reduce-cost and increased well EUR. Optimal cluster spacing was determined based on long-term production performance. The final calibrated hydraulic fracture and reservoir models were used to optimize the cluster spacing and other completion parameters.
Because of their fine-grained nature, shales exhibit substantially different reservoir properties than more conventional sandstone and carbonate reservoirs. New ideas and modified methods of reservoir characterization are required to reduce uncertainty in measuring volumetrics, drilling and stimulating a well, and gaining efficient production.
Over the past few years, our studies of unconventional gas shales in the U.S. mid-continent have led to establishing a workflow for stratigraphic characterization that addresses key issues in these unusual reservoirs. Proper characterization is multidisciplinary in nature. It includes (1) characterization of multi-scale sedimentology, litho- and sequence-stratigraphy, biostratigraphy, and geochemistry from cores, (2) relating stratigraphy to log response (including borehole image logs), (3) seismic response, (4) petrophysical and geomechanical properties, and (5) organic geochemistry. In addition, educational opportunities are being provided to university students who can then apply knowledge to petroleum industry careers. The result of this integration has led to better understanding of the evolution of shales and their contained gas, and regional to local mapping of key lithologic or stratigraphic intervals for improved drilling and production.
This paper presents the results of using a shale-specific, finite-difference reservoir simulation model to history match and forecast production data from the Barnett Shale reservoir. The paper will illustrate the many uses of the model for vertical and horizontal wells including determining gas in place, recovery factors, optimal well spacing, drainage areas and drainage shapes, optimal fracture half-lengths and conductivities, infill evaluations, horizontal well modeling and optimal number of stimulation treatments, analysis of microseismic data, and compression evaluations. The model was developed in the early 1990s to incorporate all of the production mechanisms inherent in shales including matrix gas porosity, gas desorption isotherm, single-or two-phase flow of gas and water in the natural fractures, layers, complex hydraulic fractures, and variable flowing bottomhole pressures. The paper will discuss the methodology to incorporate all field data into the simulator including core, logs, well test, completion, stimulation, microseismic, and production data. Examples will be given using public datasets. We also show production comparisons between vertical and horizontal wells since this is of topical interest in the play's development history. Furthermore, we discuss the various types of data to collect, their importance to proper stimulation design, and the integration methodology to evaluate and complete shale reservoirs.
The key objective of hydraulic fracturing in tight formation gas reservoirs is the creation of "effective" fracture length. The creation of effective fracture length requires that sufficient fracture conductivity be developed to allow effective fracture fluid cleanup. It is also fairly well understood that occasionally conventional cross-linked gel fracture stimulations do not create the desired fracture dimensions. The potential reasons for the shorter than desired effective fracture lengths are numerous with the most likely being excessive fracture height growth and poor fracture fluid cleanup. In the context of the Cotton Valley Formation bounding beds necessary to contain a large hydraulic fracture are non-existent except for the Taylor sand. Studies have been conducted of fracture fluid clean-up which indicate that fluid clean-up or more importantly the lack of fluid clean-up is a primary cause of ineffective or less than desired fracture length. This ineffective clean-up is believed to result fromthe effects of time and temperature on proppant1,gel residue and its damage to the proppant pack2,viscous fingering through the proppant pack3,the effects of unbroken gel on proppant pack permeability4,non-Darcy and multi-phase fluid flow effects5–7, andcapillary pressure8.
More recent studies9–15 have shown that for effective cleanup of fracturing fluid and length, a Dimensionless Fracture Capacity, FCD, in excess of 10 is required to overcome yield power-law effects. Dimensionless conductivities of this magnitude are not being generated with many cross-linked gel fracs.
Elimination of polymer by fracture stimulating with treated water is cheaper and may provide more effective fractures. However, the use of treated water, results in poorer proppant transport due to the low fluid viscosity. Though more of the created fracture would be effective (no polymer damage) less fracture will likely be created (poor transport). Performance comparisons of Cotton Valley wells fracture stimulated with water and cross-linked gel indicate that water fracs in addition to being cheaper also perform similarly or nearly so to cross-linked gel fracs (and in some cases better).
This paper details the application of treated water fracs to the East Texas Cotton Valley Formation and documents an evaluation of well performance and the cause and effects of hydraulic fracturing with treated water on productivity. Through developing an understanding of this well performance behavior, guidelines and/or success criteria are developed for the design and execution of successful water fracs in the Cotton Valley Formation or any tight formation gas reservoir. These guidelines consider all aspects of the fracturing process including reservoir, geomechanical, and design considerations for successful application of treated water as a fracturing fluid. These guidelines, in conjunction with an in depth review of the Cotton Valley Formation, were utilized to develop a modified "hybrid" water frac treatment that mitigates the associated risks with the use of treated water while maintaining the water frac treatment cost and clean-up advantages.
Introduction
Since being "introduced" (or re-introduced) by UPRC in 199716, water fracs have been a topic of wide and increasing interest both in the ETCV (East Texas Cotton Valley), and in other formations in North America and throughout the world. However, it has been a controversial interest, with some operators ferociously defending the idea, and others equally adamant that it does not, cannot, and will not work! This evaluation set out to determine if and why water-frac well performance is similar to conventional cross-linked gel performance in the East Texas Cotton Valley. Given this understanding, the authors anticipated that guidelines could be developed for candidate selection and application of "water frac" treatments for the Cotton Valley or any formation for that matter.
Gas shales are economically viable hydrocarbon prospects that have proven to be successful in North America. Unlike conventional hydrocarbon prospects, gas shales serve as the source, seal, and the reservoir rock. Generating commercial production from these unique lithofacies requires stimulation through extensive hydraulic fracturing. The absence of an accurate petrophysical model for these unconventional plays makes the prediction of economic productivity and fracturing success risky.
This paper presents an integrated approach to petrophysical evaluation of shale gas reservoirs, specifically, the Barnett Shale from the Fort Worth basin is used as an example. The approach makes use of different formation evaluation data, including density, neutron, acoustic, nuclear magnetic resonance, and geochemical logging data. This combination of logging measurements is used to provide lithology, stratigraphy and mineralogy. It also differentiates source rock intervals, classifies depositional facies by their petrophysical and geomechanical properties, and quantifies total organic carbon. The analysis is also employed to locate optimal completion intervals, zones preferable for horizontal sections, and intervals of possible fracture propagation attenuation. Resistivity image analysis complements the approach with the identification of natural and drilling induced fractures. We compare results from three different wells to show the effectiveness of the method for shale gas characterization.
The methodology presented provides a means to understand the geomechanical and petrophysical properties of the Barnett Shale. This knowledge can be used to design a selective completion strategy that has the potential to reduce fracturing expenses and optimize well productivity. Though developed specifically for the Barnett Shale, the underlying ideas are applicable to other thermogenic shale gas plays in North America.
The most common fallacy in the quest for the optimum stimulation treatment in shale plays across the country is to treat them all just like the Barnett Shale. There is no doubt that the Barnett Shale play in the Ft. Worth Basin is the "granddaddy" of shale plays and everyone wants their shale play to be "just like the Barnett Shale." The reality is that shale plays are similar to any other coalbed methane or tight sand play; each reservoir is unique and the stimulation and completion method should be determined based on its individual petrophysical attributes. The journey of selecting the completion style for an emerging shale play begins in the laboratory.
An understanding of the mechanical rock properties and mineralogy is essential to help understand how the shale reservoir should be completed. Actual measurements of absorption-desorption isotherm, kerogen type, and volume are also critical pieces of information needed to find productive shale reservoirs. With this type of data available, significant correlations can be drawn by integrating the wireline log data as a tool to estimate the geochemical analysis. Thus, the wireline log analysis, once calibrated with core measurements, is a very useful tool in extending the reservoir understanding and stimulation design as one moves away from the wellbore where actual lab data was measured. A recent study was conducted to review a laboratory database representing principal shale mineralogy and wireline log data from many of the major shale plays. The results of this study revealed some statistically significant correlations between the wireline log analysis and measured mineralogy, acid solubility, and capillary suction time test results for shale reservoirs. A method was also derived to calculate mechanical rock properties from mineralogy. Understanding mineralogy and fluid sensitivity, especially for shale reservoirs, is essential in optimizing the completion and stimulation treatment for the unique attributes of each shale play. The results of this study have been in petrophysical models driven by wireline logs that are common in the industry to classify the shale by lithofacies, brittleness, and to emulate the lab measurement of acid solubility and capillary suction time test. This is the first step in determining if a particular shale is a viable resource, and which stimulation method will provide a stimulation treatment development and design.
A systematic approach of validating the wireline log calculations with specialized core analysis and a little "tribal" knowledge can help move a play from concept to reality by minimizing the failures and shortening the learning cycle time associated with a commercially successful project.
Introduction
Producing methane from shale has been practiced in North America for more than 180 years. The first known well in the U.S. drilled to produce natural gas for commercial purposes was in 1821 outside of Fredonia, N.Y. (2008 www.britannica.com). This well produced from a fractured organic-rich shale through a hand dug well. It was produced for more than 75 years. Production from the Antrim shale in the Michigan Basin started in 1936. Today, there are more than 9,000 wells producing, most of which were drilled after 1987. The Barnett Shale, discovered in 1981, is being produced from more than 8,000 wells today (Wang 2008). Fig. 1 represents the growth of the Barnett Shale play in the Newark, East field in the Ft. Worth basin. The cumulative gas production from this field is more than 4 Tcf. One could characterize the success of this play as: the right market, the right people, and the right technology (Wang 2008). The key technologies for the Barnett Shale success revolve around horizontal drilling and hydraulic fracture stimulation.
The creation of highly conductive fractures has been shown to be important to the successful stimulation of wells in moderate permeability reservoirs. Therefore, the ability to determine fracture conductivity through pressure tests can be extremely beneficial to the proper design and ultimately to the success of future fracture stimulations.
Previous studies have shown techniques which can be used to determine fracture conductivity from pressure transient data. These techniques have been successfully applied to hydraulically fractured tight gas wells. This paper will illustrate the application of these techniques to wells in moderate permeability reservoirs.
This paper presents a systematic methodology to describe and characterize unconventional natural gas reservoirs. We have modified the Petrophysical Integration Process Model (PIPM), originally developed at Amoco (Gunter, et al,1,2), for specific applications to unconventional gas systems. Our modified PIPM, which is divided into four discrete analysis stages, integrates data from multiple sources and different reservoir scales. In this paper, we describe each PIPM stage and show how petrophysics can be used as the critical link between geology and reservoir engineering. Although we illustrate the process with examples from a tight gas sand study, the modified PIPM is applicable to other unconventional gas systems. The ultimate goal of this process modeling is to build realistic three-dimensional wellbore and reservoir flow models to predict future performance and optimize field development.
This paper presents a systematic methodology to describe and characterize unconventional natural gas reservoirs. We have modified the Petrophysical Integration Process Model (PIPM), originally developed at Amoco (Gunter, et al,1,2), for specific applications to unconventional gas systems. Our modified PIPM, which is divided into four discrete analysis stages, integrates data from multiple sources and different reservoir scales. In this paper, we describe each PIPM stage and show how petrophysics can be used as the critical link between geology and reservoir engineering. Although we illustrate the process with examples from a tight gas sand study, the modified PIPM is applicable to other unconventional gas systems. The ultimate goal of this process modeling is to build realistic three-dimensional wellbore and reservoir flow models to predict future performance and optimize field development.
This paper presents detailed analyses of hydraulic fracture microseismicity and engineering data created during the joint operator Cotton Valley Hydraulic Fracture Imaging Project in East Texas. The project was a joint operator consortium with the goal of evaluating hydraulic fracture growth of conventional "sandfracs" and waterfracs with very low sand concentrations. A variety of fracture diagnostic tools were used on ten fracture stages in three wells including microseismic and downhole tiltmeter fracture mapping, fracture modeling, stress tests, radioactive tracers, pressure transient well tests, and production logging. We also introduce a methodology that uses full triaxial waveform analysis of the microseismic signals to obtain seismic source parameters, which characterize failure modes during hydraulic fracturing. This information could potentially be used for a detailed description of fracture geometry, growth and complexities and may give some indications about created versus propped fracture lengths. The paper compares the microseismic created lengths and propped lengths with those from frac models.
Hydraulic fracturing treatments using treated water and very low proppant concentrations (" waterfracs") have been successful in stimulating low-permeability reservoirs. However, the mechanism by which these treatments provide sufficient conductivity is not well understood. To understand the effects of hydraulic fractures on conductivity, a series of laboratory conductivity experiments were performed with hydraulically fractured cores from the East Texas Cotton Valley sandstone formation. Jordan sand and sintered bauxite proppants were used at concentrations of 0, 0.1 and 1.0 lb m/ft2, and the conductivity was measured at effective closure stresses ranging from 1,000 to 7,000 psi.
The results of this study demonstrate that fracture displacement is required for surface asperities to provide residual fracture width and sufficient conductivity in the absence of proppants. However, the conductivity may vary by at least two orders of magnitude depending on formation properties such as the degree of fracture displacement, the size and distribution of asperities, and rock mechanical properties. In the presence of proppants, the conductivity can be proppant or asperity dominated, depending on the proppant concentration, proppant strength and formation properties. Under asperity dominated conditions, the conductivity varies significantly and is difficult to predict. Low concentrations of high-strength proppant reduce the effects of formation properties and provide proppant dominated conductivity. At conventional proppant concentrations, conductivity experiments performed with flat, parallel core faces tend to overestimate the conductivity observed with hydraulic fractures. Actual hydraulic fracture conductivity may be as much as an order of magnitude lower in the presence of low strength proppant. An important implication of this study is that the success of a " waterfrac" treatment is difficult to predict because it will depend significantly on formation properties. This dependence can be overcome by using high strength proppants or proppants at conventional field concentrations.
Introduction
Although proppants are routinely used to achieve conductivity during hydraulic fracturing treatments, recent fracturing treatments using treated water and very low proppant concentrations (" waterfracs") have been successful in low-permeability reservoirs1–4. The mechanism by which these treatments provide sufficient conductivity is not well understood. The presence of residual fracture width caused, for example, by surface asperities and proppant bridging and the lack of damage associated with the use of gels in conventional proppant treatments are possible explanations2,5. Residual fracture width has been observed during laboratory experiments6 and field tests7 and can be attributed to the combined effects of surface roughness and fracture displacement8. The surface asperities are thought to withstand high formation closure stresses and create sufficient conductivity for wells completed in very low-permeability formations. The low concentrations of proppant are added to supplement the asperities and improve overall fracture conductivity.
Factors affecting the conductivity of hydraulic fractures and proppant packs have been reported in the literature. The importance of parameters such as fracture displacement, fracture roughness, mechanical properties, and closure stress on fracture conductivity have been demonstrated in the absence of proppants9–12. When proppants are present, parameters such as proppant strength, proppant concentration, and closure stress have been shown to be important13–14. However, these studies were performed with hydraulic fracture in the absence of proppants or with proppant and flat, parallel core faces. No study has addressed the effects of hydraulic fractures on conductivity in the presence of low concentrations of proppant (i.e., conditions that may exist during waterfrac treatments).
The ability to determine the effective half-length and conductivity of hydraulic fractures is important for estimating a well's long-term production performance. The determination of these properties, along with the formation effective permeability, can result in more accurate predictions of the ultimate hydrocarbon recovery. In very low permeability reservoirs, fracture half-length is the key to optimum reservoir development. Being able to quantify these properties also allows for improved understanding of the effects of treatment design changes. Post-treatment pressure buildup testing has been the most common method for determining the effective length of hydraulic fractures. One of the major drawbacks of the pressure transient test in very low permeability reservoirs is the extremely long shut-in time required to observe a sufficient amount of the fractured well transient behavior to properly characterize the formation and fracture properties. This long shut-in time is undesirable due to the fact that the well is not able to produce and generate revenue during this time.
This paper reports on the most recent results of an ongoing study of the production performance of hydraulically fractured wells. The focus of the study is a comparison of the performance of conventionally fractured wells and those that have been completed with the treated water and low proppant concentration ("waterfrac") technique. A new evaluation technique for comparing the effectiveness of the treatments utilizing production data is introduced. The advantages and limitations of the production data analysis technique are discussed, as well as an improved understanding of the results of waterfrac treatments in low permeability gas reservoirs.
The use of a comprehensive suite of analysis techniques for the production performance of fractured wells to obtain estimates of fracture half-length, fracture conductivity and formation effective permeability is detailed. Specialized diagnostics, performance history matching with analytic solutions and specialized type curve analyses have been used for several areas to estimate the fracture and formation properties from the bilinear, formation linear and pseudo-radial flow regimes.
Introduction
The practice of pumping waterfracs has spread to a wide range geographically. The results have been mixed in that the technique works better in some areas than in others. Waterfracs must be evaluated both on technical (scientific) and economical merit. For example, the best economic solution may not always be the best from a technical standpoint. The explanation of how the waterfrac treatments work has been limited to the theory of fracture conductivity created by surface asperities (mismatches in the geometry of the fracture faces upon closure). The small concentrations of proppant pumped could also concentrate at points of reduced fracture width creating, in effect, a wedge that is able to support and keep the fracture open to a certain degree depending on the magnitude of the in-situ stress and the properties of the proppant.
Original publications related to the usage and results of waterfrac treatments pumped in the Cotton Valley sandstone formation in East Texas were published beginning in 19971–3. Since then methods to evaluate the success of the waterfrac treatments compared to conventional designs have been limited mainly to the direct comparison of well productivity. In many cases no adjustment was made for the varying conditions under which the wells were produced. Compensation for difference in flowing tubing pressure, initial reservoir pressure, differences in reservoir quality, etc. were generally not taken into account and left to the discretion of each individual looking at the comparison. The lack of accounting for these parameters is often due to the fact that the data is not readily available.
Quality reservoir descriptions require calibration of rock, pore and fluid data against production performance decline and pressure information. This paper presents a powerful three-stage integration process for building reservoir descriptions that has been successfully applied to over 80 reservoirs since 1994.
The first stage defines rock types by relating geologic framework, lithofacies and petrology to porosity, permeability and capillarity. Rock types represent reservoir units with a distinct porosity-permeability relationship and a unique water saturation for a given height above the free-water level. Relative permeability coupled with rock type data predicts production fluid ratios and residual hydrocarbon saturation. The products of stage one are rock, pore, and fluid models.
The second stage integrates rock type models with formation evaluation data to define reservoir compartments and flow units. Formation evaluation extends the rock type models and builds data transforms to compute storage capacity, flow capacity and reservoir speed. The products of stage two are petrophysical models.
The third stage uses the petrophysical models to calibrate seismic data and/or geostatistics to build a 3D reservoir description. Production tests, pressure transient data and decline curve analysis calibrate these descriptions for flow simulation.
This integrated process results in reservoir descriptions and flow models that are synergistic and powerful reservoir management tools. Over 500 BCF of gas and 45 MMBO of additional resources were identified by applying this process in the last four years. An additional 11.4 TCF of gas and 500 MMBO of recently discovered resources have been evaluated in key business areas.
This process is the focus for a year-long training program at Amoco. The training helps geologists, geophysicist, engineers and formation analysts become expert integrators of multidiscipline data to produce reservoir descriptions which are used to solve business problems.
Introduction
The business impact of applying the petrophysical integration process model (PIPM) and petrophysics project management is significant. The influence diagram (Figure 1) clearly shows front-end-loading project design reduces costs, because the ability to change decreases with time and the cost of change increases dramatically with time. Additionally, collection of some forms of reservoir data must be completed early to be representative of reservoir performance.
Our definition of petrophysics is "the synergistic process of integrating multiple disciplines to characterize and quantify rock, pore and fluid systems." This nineties' version of Archie's definition maintains the fundamental truths established in 1950.
To integrate the study of petrophysics, the PIPM is taught at Amoco as an intensive year long training program. This successful program hinges on our ability to teach, integrate and apply technologies to business problems. Working on a chosen technical project, participants receive technical training and apply techniques and interpretation methods to solve a business problem. To complete the project phase of the program they must use progress principles such as business process improvement and project management. Participants learn the fundamentals of PIPM through 80 classroom lectures, field trips, and applied workshops taught by world class consultants and in-house professionals (Figure 2). These seminars are organized around the fundamental keystones of rock, pores, fluids and project management (Figure 3).
The petrophysical integration process (Figure 4) focuses on key wells to build the basis for extrapolation to the larger field. The key well concept allows for the necessary depth of investigation and reduces cycle time. P. 475
To optimize fracture designs, rock mechanics data are needed at multiple locations in the formation and adjacent zones. This paper will review a laboratory technique that reduces testing time and cost by 60 to 80%. The technique has been successfully used on a wide variety of core and also reduces core-size requirements. Ultrasonic (dynamic) test equipment and procedures are discussed to standardize the method for petroleum industry applications and provide reliable data for fracture designs. The primary data provided are Young's modulus and Poisson's ratio. Dynamic testing has been performed on 600 cores from about 60 formations. The data are also compared to static uniaxial and triaxial data on the same cores to determine correlation coefficients between the static and dynamic data.
Procedures and apparatus for performing ultrasonic testing have been successfully developed that determine the dynamic Young's moduli for weakly consolidated cores, with Young's moduli of 60 thousand psi, to hard limestone with Young's moduli of 14 million psi. Several equations are also provided that have applications to sonic logging for mechanical property evaluation of formations. The same equipment has been used to determine fracture azimuth from oriented core at significant cost savings over other techniques. The paper will also review the relative importance of rock mechanics data on optimized fracture designs.
Introduction
Optimized fracture design treatments require data on rock properties, fracturing fluid properties and proppant properties. Our rock mechanics laboratory routinely supplies data to customers on rock and proppant properties. Optimized hydraulic and acid fracture designs require rock properties data in multiple locations in the producing interval and adjacent formations. The use of 3-D and pseudo-3-D fracture design models in recent years has increased the importance of acquiring inexpensive and rapid rock mechanics data from cores and logs. Optimized designs require, as design input parameters, Young's modulus, Poisson's ratio, fracture toughness or tensile strength and estimates of the in situ stress versus depth.
Rock mechanics data, such as Young's modulus and Poisson's ratio, can be estimated from dipole or long space sonic logs or measured in the laboratory using uniaxial, triaxial or ultrasonic testing. The preferred laboratory technique is to perform triaxial testing by simulating the in situ stress and fluid saturation conditions that exist down hole. Triaxial testing is considered as a petroleum industry standard. The primary limitations of triaxial tests is the extra cost and time to perform 8 to 15 tests on cores from one or more wells. Dynamic or ultrasonic testing is also sometimes used in lieu of triaxial testing but has never been accepted as a standard in the oil and gas industry 1.
The advantages of dynamic versus static testing can be summarized as follows:–The testing time and cost are reduced by 60 to 80%.–A nondestructive testing technique for cores that allows other cores property measurements such permeability.–Smaller samples can be tested thus reducing the minimum sample length from 2 inches to 0.5 inches for 1-inch diameter samples.–A wide variety of cores can be tested from weakly consolidated samples to hard rocks with dynamic Young's moduli between 60 thousand psi and 14 million psi.–More samples can be tested in the same zone to provide multiple values in the formation and adjacent layers in a rapid response system needed for typical fracture designs.
P. 23
Fracturing treatments using treated water and very low proppant concentrations ("waterfracs") have proven to be surprisingly successful in the East Texas Cotton Valley sand. This paper presents field and production data from such treatments and compares them to conventional frac jobs. We also propose possible explanations for why this process works.
Introduction
Hydraulic fracturing is the key technology to develop tight oil and gas reservoirs. Although millions of research dollars have been spent to date, much controversy remains about optimizing fracture design. Rock mechanics and fluid transport phenomena in hydraulic fracturing are still poorly understood. The processes are very complex with a host of unknowns. Measuring even one critical value such as net fracture treating pressure constitutes a difficult problem.
Hydraulic fracture research and development has put a lot of effort into effective placement of propping agents to provide and maintain fracture conductivity. For this purpose the service industry has developed sophisticated fracturing fluid systems and an extensive recipe of chemical additives. The fluid system is engineered to change viscosity during its journey from the surface to the fracture and afterwards during fracture cleanup. The sole reasons for these fluid designs is to place proppant, minimize formation damage and ensure proper cleanup. In turn, the proppant has no function other than maintaining a conductive fracture during well production. What would happen though if the fracture actually retains adequate conductivity with very little or no proppant?–Rock fractures often have rough surfaces. After the fracture closes, the residual aperture distribution can be very heterogeneous in all three dimensions forming a very conductive path even at high closure stresses. - Proppant along with gel residue could actually impair fracture permeability and its ability to cleanup.–Fracture extension and cleanup is easier to achieve with low viscosity fluids. Fracture extension is the key design parameter in tight reservoirs.
The above points may have a tremendous impact on the fracturing operation. Gelling agents, proppant and associated chemical additives comprise a large part of fracturing costs. In early literature, "self-propping" and "partial monolayers" of fractures has been discussed. In general though, the industry has discarded the idea. In the naturally fractured Austin Chalk the so-called "waterfrac treatments" are pumped with no propping agents. They are very successful. Why it works is still generally unknown.
The hydromechanical response of natural fractures has been addressed in rock mechanics literature. It is an extremely important issue in the field of underground nuclear waste disposal. The effect of normal stress and shear stresses on a fracture (natural and artificial) dictate its conductivity. The ramifications of these forces on fracture propagation are just now beginning to be investigated (multiple fractures). Description of "Waterfracs"
The following outlines the general pumping schedule (from here on, the treatments will be referred to as "waterfracs"). P. 457
This paper uses case histories to introduce a graphical method for easily quantifying reservoir flow units based on geologic framework, petrophysical rock/pore types, storage capacity, flow capacity, and reservoir process speed. Using these parameters and four graphical tools, this paper outlines a quantitative approach to transform rock-type-based zonations into petrophysically based flow units that can be input into a numerical flow simulator. This method provides a tool for determining the minimum number of flow units to input into a numerical flow simulator that honors the foot-by-foot characteristics at the wellbore.
A flow unit is a stratigraphically continuous interval of similar reservoir process speed that maintains the geologic framework and characteristics of rock types. Rock types are representative reservoir units with a distinct porosity-permeability relationship and a unique water saturation for a given height above free water level.
The ideal data for this method is continuous core porosity, permeability, and saturation information drawn from throughout the entire reservoir. If such a data set is not available, it is necessary to calibrate wireline log data with core information to produce reliable estimates of porosity, permeability, and saturation. A full discussion of these data transforms are beyond the scope of this paper.
The four graphical tools used to determine flow units are: Winland porosity-permeability cross plot, Stratigraphic Flow Profile (SFP), Stratigraphic Modified Lorenz Plot (SMLP) and Modified Lorenz Plot (MLP).
This method begins by establishing rock types within a geologic framework. The geologic framework allows the flow units to be interpreted within a sequence stratigraphic model determining well-to-well correlation strategies. The key flow unit characteristics to be identified are barriers (seal to flow), speed zones (conduits), and baffles (zones that throttle fluid movement).
This integrated, petrophysically based method of determining flow units has been successfully used in a wide array of reservoirs. We have applied it to young, unconsolidated sediments; structurally complex naturally fractured/vuggy carbonates; low permeability "tight" formation gas sands; diagenetically altered carbonates; complex mixed lithologies; and interbedded sand-shale sequences.
The earlier in the life of a reservoir this process is used, the greater the understanding of future reservoir performance. This method allows the user to employ the least number of flow units and honor the character of the foot by foot data for simulation studies.
Key Definitions
Due to various working definitions of some of these terms in the literature, it is necessary to define the key terms used in this approach:
Rock Types
Rock/Pore Types - are units of rock deposited under similar conditions which experienced similar diagenetic processes resulting in a unique porosity-permeability relationship, capillary pressure profile and water saturation for a given height above free water in a reservoir.
Winland Plot - a semi-log crossplot of permeability (mD) versus porosity (%), with isopore throat lines (R35 Ports). R35 Ports correspond to the calculated pore throat radius (microns) at 35% mercury saturation from a mercury injection capillary pressure test. They can be calculated directly from Winland's equation (eq. 1) or other equations based on permeability and porosity. In equation 1, permeability is input in millidarcies and porosity in percent.
(1)
P. 373
There is a growing awareness among petroleum engineers of the value of rock mechanics based analytical approaches to wellbore stability and sand production problems. It is readily accepted that the key to successful engineering lies in the acquisition of reliable data. Geomechanical properties testing is often perceived, however, as being expensive. All to often only limited numbers of samples are tested. This paper demonstrates how porosity can be employed as a geomechanical index to enable rock mechanics materials properties to be estimated using general and field specific correlations. Such an approach can be used to extend the application of a limited number of calibration samples.
General correlations exist between porosity and the uniaxial compressive strength and Young's modulus of sandstones and carbonates. Most of the work reported in the literature has concentrated on correlating porosity with absolute values of mechanical properties. Strength is, however, a stress sensitive property, increasing as confining stress increases. It is shown that porosity correlates with the constants required to construct theoretical and empirical failure criteria which describe such behaviour. Porosity also reflects other geomechanical characteristics of sedimentary rocks including failure mode, fracture intensity, drilling rate and perforation penetration.
The utility of porosity as a geomechanical index enables existing core and log data to be utilised to extend the use of limited core material.
Low-permeability reservoirs from the Greater Green River basin of southwest Wyoming are not part of a continuous-type gas accumulation or a basin-center gas system in which productivity is dependent on the development of enigmatic sweet spots. Instead, gas fields in this basin occur in low-permeability, poor-quality reservoir rocks in conventional traps. We examined all significant gas fields in the Greater Green River basin and conclude that they all occur in conventional structural, stratigraphic, or combination traps. We illustrate this by examining several large gas fields in the Greater Green River basin and suggest that observations derived from the Greater Green River basin provide insight to low-permeability, gas-charged sandstones in other basins. We present evidence that the basin is neither regionally gas saturated, nor is it near irreducible water saturation; water production is both common and widespread. Low-permeability reservoirs have unique petrophysical proper-ties, and failure to fully understand these attributes has led to a misunderstanding of fluid distributions in the subsurface. An understanding of multiphase, effective permeability to gas as a function of both varying water saturation and overburden stress is required to fully appreciate the controls on gas-field distribution as well as the controls on individual well and reservoir performance. Low-permeability gas systems such as those found in the Greater Green River basin do not require a paradigm shift in terms of hydrocarbon systems as some have advocated. We conclude that low-permeability gas systems similar to those found in the Greater Green River basin should be evaluated in a manner similar to and consistent with conventional hydrocarbon systems.
The Haynesville Shale is an unconventional gas reservoir located in east Texas and northwest Louisiana. High gas prices and the success of other shale gas plays have led operators to invest highly in this unconventional reservoir. It has great potential for development by applying all the new technology that is available in the oil and gas industry today.
Petrophysical evaluation of reservoirs has long been used for exploration and reserve estimates. New logging tools and analysis techniques have been developed to provide more precise data about target zones and bounding layers that are important when considering hydraulic fracturing for unconventional reservoirs.
A processed log interpretation calibrated for the Haynesville Shale is computed using a typical triple-combo suite of logs. Other log data, such as borehole imaging, magnetic resonance, dipole sonic, and spectral gamma ray, will improve and verify the interpretation. Core analysis provides accessory data on mineralogy, total organic carbon (TOC), and rock mechanical properties to calibrate this processed log computation and improve the accuracy of the total shale interpretation.
Identification of the following reservoir characteristics provides the starting point for completion-and hydraulic-fracture stimulation design: Identification of free-gas zonesIdentification of rock types and mineralogyTotal organic contentQuantification of effective shale porosityEstimates of shale permeabilityMechanical stress measurement for hydraulic-fracturing designIdentification, classification, and orientation of marginal-class, open-conductive, and drilling-induced fractures
A number of Haynesville Shale examples are presented to highlight all interpretation techniques and variations in the shale itself within its proven productive area. This interpretation can be critical for the hydraulic-fracture design approach for the Haynesville Shale.
The objective of hydraulic fracturing is to design and execute a fracture stimulation treatment that achieves the desired fracture dimensions (length and conductivity) to maximize a wells production rate and reserve recovery. To achieve this objective, there are several critical parameters to the process, and these fall into two distinct categories:parameters over which we have little control, but need to understand, andthose that we control, but have lesser impact on the process.
The first category includes fracture height, fluid loss coefficient, tip effects, and Young's modulus. The second category includes pump rate and fluid viscosity. Of the former parameters, Young's Modulus is the only variable that can be measured, in advance, via lab tests.
Traditionally, Young's Modulus is measured through stress-strain testing of geologic samples (core plugs) which always demanded an L/d (Length/ diameter) ration of at least 2:1. The reason for this criterion is that the ultimate failure mechanism for most rocks under compression loads is the formation of a shear fracture. For most rock types, this shear fracture will form at an angle of about 30° from the axis of the maximum compression load. Thus, a 2:1 L/d ratio allows a through-going shear fracture to form for a failure angle of 30°. For stress-strain testing NOT concerned with ultimate failure of the sample, this valid criterion has always been followed - arbitrarily and artificially. Unfortunately, this sample criterion generally eliminates the use of sidewall cores.
This paper details and documents an evaluation of the Length to diameter criteria through finite element modeling, tri-axial compression testing of aluminum, and compression testing of actual sedimentary rock samples. Through this work, it is evident that core samples of L/d significantly less than 2:1 can provide reliable values of static Young's Modulus. Further, these results indicate that rotary sidewall cores can be utilized to determine Young's Modulus in many applications provided adequate sample quality assurance is undertaken to ensure sample integrity.
Introduction
Determination of mechanical rock properties is important to the oil and gas industry for reservoir compaction, borehole stability, formation control, and hydraulic fracturing. Measurements of the elastic rock properties have historically been conducted on whole core and via wireline measurements once the wellbore has been drilled. Application of these methods at the well site in real time on drill cuttings and with Measurement While Drilling (MWD) to improve or optimize the drilling process is the focus of much ongoing research1–5. Studies by Ringstad et al2, Zausa et al3, and Santarelli et al4 evaluated the use of drill cuttings for mechanical properties determination. Because of this, these studies focused on sample size sensitivities and determined that the micro indentation measurements correlated well to Uniaxial Compressive Strength of the rock. However, these measurements correlated poorly with Young's Modulus or porosity.
Similarly, Nes et al5 investigated sample size sensitivities on both the static and dynamic behavior of the Pierre Shale. This study evaluated the elastic properties of 0.39 inch diameter samples 0.16 inches in length (L/d = 0.4) and found that the static Young's Moduli of the "hard" shale samples was in excellent agreement (i.e. within 3.5 %) with larger sized core plugs. The static Young's Moduli of the soft shale samples tested were in much poorer agreement (i.e. nearly a 20 % error) as compared to larger sized samples tested. Finally, this work showed excellent agreement (i.e. +/− 2 %) between the dynamic moduli determined with a Continuous Wave Technique (CWT used on smaller samples) and a Pulse Transmission Technique (used on larger samples).
SPE Member
Abstract
An understanding of the mechanical properties of petroleum reservoirs is important for drilling, well stimulation and horizontal well development. Static and dynamic rock mechanical properties were measured on a suite of core samples taken through the Chase and Council Grove carbonate sequences of the Hugoton and Panoma fields, Kansas. The purpose of the study was to characterize the mechanical properties of the different facies and calibrate the dynamic mechanical properties so acoustic well logs from other wells can be utilized more effectively in determining areal and lithologic variation in mechanical properties of the field.
The mechanical properties of rocks can be measured in the laboratory from triaxial tests ("static" tests) or they can be estimated from wireline measurements of compressional and shear acoustic velocities and rock density ("dynamic" tests). Static measurements on cores are much more indicative of the mechanical properties of the reservoir than the dynamic results, however, the information from acoustic well logs covers much more of the reservoir than core measurements and is less expensive. Since there can be significant differences between static and dynamic values, it important to be able to translate the "dynamically" derived mechanical properties to the static values which better represent the reservoir.
Results of the tests show that Young's modulus correlates strongly with lithofacies and porosity. The Chase and Council Grove carbonate sequences can be separated into six "mechanical facies", defined by their modulus-porosity trends and their lithology. Only small percentages of secondary minerals (dolomite and anhydrite) appear necessary to alter the rocks properties significantly. Poisson's ratio is less sensitive to lithology but correlates with porosity. The dynamic Young's moduli are higher than the static values but dynamic and static Poisson's ratios correlate well with each other for liquid saturated samples.
Dynamic to static transforms based on lithofacies were developed from these data to correct the acoustic log derived mechanical properties to static values appropriate for reservoir deformations. The corrected mechanical properties along with the trends observed between mechanical properties, lithofacies, and porosity allow for the design of more effective hydraulic fracture treatments by utilizing accurate values for the reservoir's mechanical properties and their variability.
P. 209^
In SPE 38611 "Proppants, We Don't Need No Proppants" data showed that fracture treatments using treated water and very low proppant concentrations (waterfracs) were very successful in the East Texas Cotton Valley sandstone. The paper presented limited initial results from one operator in one field. Following this paper a more comprehensive set of production comparisons of wells completed with standard frac jobs and waterfracs since 1996 for several different operators in the East Texas area are presented. Analysis of offset comparisons, economics, and other benefits are described from the aspect of several different operators.
Conclusions will point out the cost savings and the ability to exploit marginal reserves with this technique. There will also be a perspective from each operator. The waterfrac technique has led to widespread discussions among many operators in various tight gas plays. Many operators are experimenting with the technique and experiencing excellent results. This technique is a major contribution to the reduction in completion costs in wells that must be hydraulically fractured. The industry has experienced a major inflation of well construction costs and this technique will be of paramount importance in our efforts to keep costs down in order to continue to develop tight gas reserves. Techniques such as these require many months of production in order to analyze to determine the actual results. Several techniques and the perspectives of several operators and how they make these important decisions will be presented here.
P. 497
In previous publications we showed that several fracture treatments using treated water and very low proppant concentrations (waterfracs) were very successful in the East Texas Cotton Valley sandstone. This paper expands on the production examples with a more comprehensive set of production comparisons of wells completed with standard fracture treatments and waterfracs since 1995. The data sets are from three different Cotton Valley fields and include approximately 50 waterfrac treatments.
P. 489
Thesis (Ph.D.)--University of Tulsa, 1982. Includes bibliographical references (p. 311-315). Photocopy.
Dynamic Rock Mechanics Testing for Optimized Fracture Designs, " paper SPE 38716, presented at the 1997 Annual Fall Technical Conference and Exhibition
- L L Lacy
Lacy, L.L.: " Dynamic Rock Mechanics Testing for Optimized Fracture Designs, " paper SPE 38716, presented at the 1997 Annual Fall Technical Conference and Exhibition held in San Antonio, TX, Oct. 5-8, 1997.
Porosity as a Geomechanical Indicator: An Application of Core and Log Data and Rock Mechanics, " paper SPE 28853, presented at the European Petroleum Conference
- R A Farquhar
- J M Somerville
- B G D Smart
Farquhar, R.A., Somerville, J.M., and Smart, B.G.D.: " Porosity as a Geomechanical Indicator: An Application of Core and Log Data and Rock Mechanics, " paper SPE 28853, presented at the European Petroleum Conference held in London, UK, Oct. 25-27, 1994.
Application of Low Viscosity Fracturing Fluids: Water-Frac’s
- Britt
Britt, L.K.: " Application of Low Viscosity Fracturing Fluids: Water-Frac's, " 2007-2008 SPE Distinguished Lecture Series.
Fracture Optimization and Design Via Integration of Hydraulic Fracture Imaging and Fracture Modeling: East Texas Cotton Valley
- L K Britt
Britt, L. K, et al, " Fracture Optimization and Design Via Integration of Hydraulic Fracture Imaging and Fracture Modeling: East Texas Cotton Valley, " SPE 67205, SPE Productions & Operations Symposium, Oklahoma City, March 24-27, 2001.
Horizontal Well Completion and Stimulation Optimization and Risk Mitigation Strategies, " paper SPE 125526 presented at the SPE Eastern Regional Meeting held in Charleston
- L K Britt
- M B Smith
Britt, L. K. and Smith, M. B.: " Horizontal Well Completion and Stimulation Optimization and Risk Mitigation Strategies, " paper SPE 125526 presented at the SPE Eastern Regional Meeting held in Charleston, West Virginia, Sept. 23-25, 2009.
Fracturing of High Permeability Formations Mechanical properties Correlations," paper SPE 26561, presented at the 68th Annual Fall Technical Conference and Exhibition
- H H Morales
- R P Marcinen
Morales, H.H., Marcinen, R.P.: " Fracturing of High Permeability Formations Mechanical properties Correlations, " paper SPE 26561, presented at the 68 th Annual Fall Technical Conference and Exhibition held in Houston, tx, Oct. 3-6, 1993.
Dynamic and Static Elastic Properties of Saturated Sandstone Samples
- Tuman
Tuman, V.S. and Alm, R.F.: " Dynamic and Static Elastic Properties of Saturated Sandstone Samples, " paper SPE 603.