Top PDF Fracture Conductivity Behavior in Shale Formations

Fracture Conductivity Behavior in Shale Formations

Fracture Conductivity Behavior in Shale Formations

The way rock fails enabling the creation of a fracture depends on the stress distribution downhole in the field, and also on the mineralogy distribution of the formation. For whatever the reasons, the fractures created by hydraulic power in the field all have certain degree of unevenness along the fracture face. To understand fracture conductivity behavior, using artificially fractured samples represent an improvement to better emulate the fracture surfaces in the field. For an uneven surface, proppant concentration varied along the fracture surface. Meanwhile, some areas of the fracture surface carried a higher level of stress than others. This non-uniform stress profile along the fracture surface can occur any time the two fracture surfaces do not come in perfect contact with each other. These two features caused by fractured surface topography, uneven proppant distribution and uneven stress distribution, can both enhance fracture conductivity. Hundreds of fracture conductivity experiments were conducted under different test conditions, including by Enriquez (2016), and as summarized and analyzed by Kainer et al. (2017), and others using the same Modified API Fracture Conductivity Cell utilized in this study. All of them used a rough fractured surface instead of a saw-cut smooth surface. Yet, the self-channeling phenomenon was observed in only in a small portion of the tested samples.
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Predicting Hydraulic Fracture Conductivity In Shale Plays

Predicting Hydraulic Fracture Conductivity In Shale Plays

Similar results are obtained as we observed in the other shale samples that closure stress and proppant concentration are the key drivers in the conductivity behavior. However, Young’s modulus and surface roughness were also found to be influential. According to the positive 𝛽 coefficient, a higher modulus resulted in higher conductivity values overall. Surface roughness was significant in this case due to the lower proppant concentrations of 0.01 lb/ft 2 . These values are within the proppant monolayer range where surface asperities can create pinch points in the fracture as well as tortuous flow paths, which inhibit conductivity. This agrees well with a 𝛽 value of -4.55 for surface roughness, exhibiting an inverse relationship with conductivity. Poisson’s ratio was found to have no statistically valid effect on fracture flow performance. Interaction terms between Young’s modulus, surface roughness, and proppant concentration were also investigated but none were found to be statistically significant.
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The Effect of Proppant Size and Concentration on Hydraulic Fracture Conductivity in Shale Reservoirs

The Effect of Proppant Size and Concentration on Hydraulic Fracture Conductivity in Shale Reservoirs

Hydraulic fracture conductivity in ultra-low permeability shale reservoirs is directly related to well productivity. The main goal of hydraulic fracturing in shale formations is to create a network of conductive pathways in the rock which increase the surface area of the formation that is connected to the wellbore. These highly conductive fractures significantly increase the production rates of petroleum fluids. During the process of hydraulic fracturing proppant is pumped and distributed in the fractures to keep them open after closure. Economic considerations have driven the industry to find ways to determine the optimal type, size and concentration of proppant that would enhance fracture conductivity and improve well performance. Therefore, direct laboratory conductivity measurements using real shale samples under realistic experimental conditions are needed for reliable hydraulic fracturing design optimization.
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A Comprehensive Study of the Eagle Ford Shale Fracture Conductivity

A Comprehensive Study of the Eagle Ford Shale Fracture Conductivity

Hydraulic fracturing is a stimulation process that involves pumping a pressurized mixture of fluids, chemicals and proppants (usually sand) down a well. On high permeability reservoirs the objective of hydraulic fracturing is to bypass a damage zone near the wellbore. On the other hand, in low permeability formations like shale reservoirs the objective is to increase the contact area with the reservoir so commercial flow rates can be obtained. The hydraulic fracturing process begins with pumping pad fluid at pressures higher than the formation fracturing pressure which fractures the rock. Next, proppants are added to the fluids and it is expected that the proppants will fill the newly created fractures and keep them open once the pumping stage is over. Chemicals are added at every stage of the hydraulic fracturing process. These chemicals are used to reduce the friction between the slurry and the pipe, increase and maintain the fluid viscosity, limit corrosion and scale deposition in the pipe, clean the perforations and to avoid/minimize formation damage.
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The Effect of Rock Properties on Hydraulic Fracture Conductivity in the Eagle Ford and Fayetteville Shales

The Effect of Rock Properties on Hydraulic Fracture Conductivity in the Eagle Ford and Fayetteville Shales

In order to characterize the mechanical properties of the shale formations, a triaxial rock testing system was used. The GCTS RTX-1500 Triaxial Rock Testing System is specifically designed to test rock parameters such as Young’s Modulus and Poisson’s Ratio while controlling confining and pore pressures. The system is capable of measuring the properties of rock samples with diameters up to 2 inches and sample lengths up to 4 inches. An axial load of up to 1500 kN can be applied to the rock. The system is capable of confining pressures of up to 20,000 psi. It is also capable of maintaining an internal rock pore pressure of up to 20,000 psi. For the purposes of this research, the full loading capabilities (axial, confining, and pore) were unnecessary. The pore pressure capabilities were not used at all. The major benefit of the GCTS RTX- 1500 system is the deformation instrumentation and data acquisition. Internal instrumentation, using Linear Variable Differential Transformers (LVDTs), is able to measure axial and circumferential deformations as small as 0.001 millimeters. The RTX- 1500 meets the specifications of the International Society of Rock Mechanics (ISRM) for rock sample triaxial tests.
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The Effects of Fracture Orientation and Anisotropy on Hydraulic Fracture Conductivity in the Marcellus Shale

The Effects of Fracture Orientation and Anisotropy on Hydraulic Fracture Conductivity in the Marcellus Shale

To approximate horizontal fractures, samples were broken parallel to the bedding planes. Although the bedding planes may have a non-zero dip angle at formation depths, the dip angle is assumed to be low enough to make this a valid approximation. That said, fractures in formations such as the Marcellus do not usually propagate horizontally because of the large overburden pressure at depth. However, the current literature on the subject of propped fracture conductivity has used horizontally-fractured samples for discussion. Operators who test fracture conductivity also generate samples with this fracture orientation, meaning that horizontally-fractured samples remain the best way to compare results from this work to those from previous studies or operator data.
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A Study on the Effect of Water Damage to Fracture Conductivity in the Meramec Shale

A Study on the Effect of Water Damage to Fracture Conductivity in the Meramec Shale

Additionally, we can draw a correlation between the mineralogical content of these for- mations and the resulting unrecoverable loss in conductivity after water exposure. Similar to the clay content results, the loss in conductivity due to water follows the same trend. The Barnett Shale had the highest clay content at 55%, and it also had the largest loss in conduc- tivity ranging from 80 to 97% loss in fracture conductivity as reported by Zhang (2014). The Marcellus had an average clay content of 26.5%, and it had an average loss in conductivity of 42.5% as reported by Guerra et al. (2017b). The Meramec core tested contained an average clay content of 23.7%, and average unrecoverable loss in fracture conductivity was found to be 41.9%. Lastly, Guerra et al. (2017b) reported unrecoverable loss in conductivity span- ning the five Eagle Ford subunits to be 4.2% up to 24.8%, with a maximum clay content of 13.5%. Characterization of the Meramec formation has shown strong similarities to the Mar- cellus with regards to clay content and resulting loss in conductivity. Figure 4.11 illustrates the Meramec cores tested, the bright green triangles, versus previously tested formations; the Barnett, Eagle Ford, and Marcellus Shales based upon their respective clay content and loss in conductivity. The Meramec samples tested performed similar to the Marcellus out- crop samples, and these cores follow the trend established by the previously tested formation conductivity tests.
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Creation and Impairment of Hydraulic Fracture Conductivity in Shale Formations

Creation and Impairment of Hydraulic Fracture Conductivity in Shale Formations

2010), water tends to flow through the fractures under differential pressure. Osmosis is considered as an important mechanism of ion migration because shale acts as a semi- permeable membrane (Low and Anderson 1958). The osmotic efficiency of clay depends on its porosity, salinity, cation exchange capacity, and confining pressure (Fritz and Marine 1983; Mody and Hale 1993). Capillary pressure is the pressure difference across the interface between two immiscible fluids. It is a function of interfacial tension, contact angle and the effective radius. Chenevert and Sharma (1993) believed that the driving force of water movement can be best described by the concept of total aqueous potential differences between shale water and injected water. They also found that the time- dependent shale swelling process is usually followed by a steady state process.
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Evaluation of the Organic Carbon Content in the Low-Permeability Shale Formations (As in the Case of the Khadum Suite in the Ciscaucasia Region)

Evaluation of the Organic Carbon Content in the Low-Permeability Shale Formations (As in the Case of the Khadum Suite in the Ciscaucasia Region)

original concentration of OM in Bathian-Bajocian clays is 2.7-3.12% (the mean value is 2.9%), in the Aptian-Albian deposits – 3.9 to 4.4% (the mean value is 4.15%), in the deposits of the Khadum suite – 3-5.5% (the mean value is 4.7%). Due to that, the average hydrocarbon potential was increased 1.5-2 times. Based on the results of initial source rock state recovery, we have made a map of initial organic carbon content that allows to give a reliable estimate of generation potential for the source rocks of the Khadum suite, and to determine the perspectives of hydrocarbon accumulations exploration in the low-permeability shale formations of Ciscaucasia.
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A study into the mapping of an induced fracture in a fine grained sediment in biaxial and triaxial stress formations

A study into the mapping of an induced fracture in a fine grained sediment in biaxial and triaxial stress formations

; the maximum width starts at 0.41mm but then decreases and remains steady at 0.23mm throughout. This corresponds to the fracture half-length decreasing in height as it was propagated further away from the borehole as opposed to increasing in height as observed in half-length 1 and other samples. The lack of further reduction in width suggests that what has been traded for as a loss of height in the fracture as it propagates has been made up for in maintaining the fracture width as the absence of further narrowing means that there was a lower requirement to dissipate pressure from the fracturing fluid and thus an increase in the fracture height was unnecessary. This can be seen by the negative correlation when the fracture height is plotted against the width, Figure 5-56, where, barring one anomalous result, there is a clear negative correlation of decreasing width against increasing height. With an equation of y=-1506.2x +445.96 and an r 2 value of 0.94 the trend line is close fit for
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Main controlling factors of fracturing fluid imbibition in shale fracture network

Main controlling factors of fracturing fluid imbibition in shale fracture network

The two groups of water imbibition experiments have con- sistent results, indicating higher experimental repeatability. As the water imbibition time advances, the water spontaneously enters into the pores of the shale matrix, and the sample mass gradually increases. It is indicated that the water imbibition of fracturing fluid into shale reservoirs is the main reason for the generally low flowback efficiency. At the beginning of the laboratory experiment, the sample mass is increased rapidly with the soaking time. At the later stage of experiment, the sample mass did not change much and eventually tends to be stable. According to Ma et al. (1997), the laboratory experi- ments and the field application have the same dimensionless time:
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Studies of Fracture Damage Caused by Proppant Embedment Phenomenon in Shale Rock

Studies of Fracture Damage Caused by Proppant Embedment Phenomenon in Shale Rock

Effective packed fracture with the proppant for cylindrical steel plugs and shale rock 449. 450[r]

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Regulatory Fracture Plugging: Managing Risks to Water From Shale Development

Regulatory Fracture Plugging: Managing Risks to Water From Shale Development

From an economic perspective, the goal of environmental policy should be the level of environmental quality that maximizes aggregate welfare. Then, the ideal tool is the one that would achieve that goal at the lowest cost to society (including administrative, compliance, en- forcement, and other costs). Identifying this tool or combination of tools requires grappling with the nature of the specific environmental externality, the incentives of various actors, and the comprehensive- ness of existing regulation-based, market-based, or litigation-based risk management. The most important considerations for identifying risk-management tools in the environmental context, then, are risks, incentives, and cost-benefit analysis. These cornerstone principles pro- vide a useful framework for environmental policy in general, espe- cially in situations that involve heterogeneous and uncertain risks. By paying attention to risk, incentives, and cost-benefit analysis, govern- ment regulators are more likely to promote optimal levels of environ- mental quality and avoid unintended, or even perverse, consequences. To demonstrate the usefulness of these concepts concretely, this Ar- ticle applies them to the fracking context, focusing on the most promi- nent risks from widespread shale development: risks to water from
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Fracture spatial arrangement in tight gas sandstone and shale reservoir rocks

Fracture spatial arrangement in tight gas sandstone and shale reservoir rocks

cores from said interval hinders further understanding of any potential association between the two. Unlike Set 2 fractures, fractures in the other two sets all are concentrated in the first half of the wellbore. It has been observed previously that Set 1 fractures are predominantly conductive and that Set 3 fractures are predominantly sealed and that the number of fractures in the major type is approximately an order of magnitudes or above more than the minor type (Table 7). Unlike fractures in HRB-1, fractures in HRB-2 have not been categorized by the continuity or their trace resistivity, and therefore there’s no further information on the picking of the minor components of fractures in the same Set. However, since the NCC results for the Natural fracture superset #1 and 3 (Figures 10-59, 63) indicate that combining each Set’s major and minor type components does not markedly affect the spatial arrangement outcome (which reflect the results of the major types), it may be safe to conclude that the sealed Set 1 fractures and the conductive Set 3 fractures share origins with their conductive or sealed counterparts, respectively. Note that the statement does not apply to Set 2 fractures, for, other than our earlier discussion on the non-overlapping clusters between the two types, the NCC result (Figure 10-61) as well as the Cv (Table 7) also show significant increase in statistical randomness comparing the Natural superset #2 to each of its constituent sets.
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Impact of Geo-mechanical Properties on the Fracture Treatment of Utica Shale

Impact of Geo-mechanical Properties on the Fracture Treatment of Utica Shale

Paktinat et.al (7) conducted research in Utica shale formation. Their study gives a general survey about geology of Utica shale formation and reservoir properties such as thickness, porosity and permeability and also compares Utica shale with other Appalachian basin shale formations like Marcellus and Lewis. In addition, it provides more information about Utica mineralogy. This study discussed how the fracturing treatment and production can be improved. They suggested to optimize the fracturing fluid by studying the impact of clay’s content on the formation stability and proved that using KCL is helpful to stabilize high clay content formations. Also the study gives general overview about the geo- mechanical properties such as Young’s Modulus and poison’s ratio (7)
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The Effect of Rock Properties on Fracture Conductivity in the Eagle Ford

The Effect of Rock Properties on Fracture Conductivity in the Eagle Ford

almost one to one. Additionally, the Poisson’s ratio follows the same trend of the Young’s modulus values. The parallel samples have a greater Poisson’s ratio average than the perpendicular sample. The slight difference in the averages may be a result of the different layers of mineralogy present in the samples. Since the difference in the elastic properties is minimal, it would be difficult to conclude a significant effect on the conductivity values. Moreover, the perpendicular samples have a higher Brinell hardness number than the parallel samples. This trend does not follow the elastic trends found. A possible explanation is that the perpendicular sample’s rock surface was tested on a “stiff” layer with hard minerals present such as quartz. However due to there being only one perpendicular sample, further testing of additional perpendicular samples would be needed in order to obtain a better representative average. The difference between the Brinell hardness values reported suggest that there could be a considerable effect on fracture conductivity. Overall the rock properties measurements obtained present a low variation between the two orientations.
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Isotopic investigation of subsurface rock and fluid interactions: Case studies of CO2 sequestration and gas-bearing shale formations

Isotopic investigation of subsurface rock and fluid interactions: Case studies of CO2 sequestration and gas-bearing shale formations

Geologic carbon storage and unconventional gas drilling are both activities that change the physical and chemical state of the geologic formations that they target. Both cause increases in formation pressure that can result in the displacement of deep-seated brines and an increase in formation porosity and permeability. These brines have the potential to travel along porous pathways and interact with adjacent or overlying fluids. Aside from the physical changes in the formation, the formation can dissolve and new minerals can precipitate. The reactions that occur between the anthropogenic fluids and the overlying seal rock are also important, as this seal rock provides the pressure necessary for successful carbon storage and recovery of hydrocarbons. If seal rock integrity is compromised, the result could be a permeable pathway for upward fluid migration.
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Study on the fracture mode of low permeability shale under different confining pressures

Study on the fracture mode of low permeability shale under different confining pressures

Since Cook (1965) found that the stress-strain curve of the whole rock, people began a lot of experimental research on the fracture process of rock. A number of studies have indicated that the failure of the rock occurs at a point after the peak load, not at the point of peak strength. The rupture is no longer seen as a state, but rather a process, a process known as the deterioration of the material [2]. So far, a lot of research about the rock fracture is still in use of the traditional strength theory. In mining engineering, such as mining, slope, drilling and blasting, especially in deep mining of coal mine production, and often encounter "rock burst" and "coal explosion" phenomenon of rock burst. This phenomenon not only seriously damage the underground engineering structure, but also threaten the safety of the production personnel. But just here, the traditional failure criterion is invalid. On the other hand, it is more important to predict and prevent the instability of a lot of underground structures than simply studying the strength limit. Therefore, many of the same issues related to mining damage in geotechnical engineering, people are concerned about not only the peak strength, bearing capacity and rupture after rupture of precursory information is also an important problem of rock mechanics are concerned. Study of rock failure is only a state of rupture process, not simply seek to put forward such as Mohr- -Coulomb kind of rock under the condition of laboratory overall failure strength criterion according to, because it is not applicable to the load deformation and fracture process research. The study of the rupture process often appears to be more important than the destruction of the study itself [2]. In this paper, the fracture modes of rock under different confining pressures are studied by experiments.
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Preliminary account of Late Devonian palynomorph assemblages from the Bedford Shale and Berea Sandstone Formations of central Ohio, U.S.A.

Preliminary account of Late Devonian palynomorph assemblages from the Bedford Shale and Berea Sandstone Formations of central Ohio, U.S.A.

Four samples collected across the boundary between the Bedford Shale and Berea Sandstone Formations in central Ohio have yielded well preserved assemblages of both miospores and mi[r]

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Analysis of Water Based Fracture Fluid Flowback to Determine Fluid/Shale Chemical Interaction

Analysis of Water Based Fracture Fluid Flowback to Determine Fluid/Shale Chemical Interaction

The initial values of the water concentrations (base case) for the water/rock experiments were obtained from a water analysis report done by the Soil, Water and Forage Testing Laboratory of the Department of Soil and Crop Sciences, Texas A&M University. Table 5.1 shows the values of the tap water obtained from the lab where the experiments were carried out. For the base case of the fracture fluid/rock experiments, the total dissolved solids (TDS) value in the fracture fluid was computed by adding the TDS of tap water to the quantities of the solid components and the concentration of each element in the liquid components of the fracture fluid recipe. For the solids, a straightforward conversion to parts per million (ppm) was all that was required (i.e. a total of 26.5 lb/mgal (3.18 g/L) from the gelling agent and the breakers were converted to 3183.6 ppm). For the liquid constituents, more detailed calculations were employed using the information obtained from the MSDS sheets, atomic weight, density and mass of each element. The result of said calculations yielded ~8650 ppm of dissolved solids.
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