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Abstract Shale gas resource plays an increasingly important role in energy supply worldwide. Hydraulic fracturing of horizontal wells is crucial for economic production of shale gas. Gas in shale reservoirs is mainly composed of free gas within fractures and pores and adsorbed gas in shale matrix. With gas production, more gas may be released or desorbed because of substantial pressure depletion, especially during late time of gas production. However, hydraulic fractures may close to some degree based on proppant quality and shale hardness, resulting in decreasing gas production. Impacts of gas desorption and geomechanics in hydraulic fractures, i.e., stress-dependent propped fracture conductivity, on ultimate gas recovery are not clearly understood and systematically investigated. Additionally, most reservoir modeling work in the literature have usually ignored the gas desorption and geomechanics effects together. Therefore, it is absolutely critical to study and evaluate the impacts of gas desorption and geomechanics on gas recovery for different shale reservoirs. In this paper, we perform history matching with two field gas production data from Barnett Shale and Marcellus Shale, and first analyze the positive contribution of gas desorption and the negative effect of geomechanics on gas production, respectively, and then compare these two effects on gas production with the purpose of identifying which effect is dominant in the whole process of gas production. Furthermore, we numerically study the effect of gas desorption on gas recovery with available laboratory data of Langmuir isotherm from five different shale formations including Barnett Shale, New Albany Shale, Eagleford Shale, Marcellus Shale, and Haynesville Shale. The impact of different fracture spacing on gas desorption is considered. Also, we use the method of Design of Experiment (DoE) to perform sensitivity studies with six uncertain parameters such as reservoir permeability, bottom hole pressure (BHP), fracture conductivity, initial reservoir pressure, porosity, and fracture spacing to screen insignificant parameters and obtain critical parameters that control this process. This paper enables operators to develop an early better understanding of the effects of gas desorption and geomechanics on shale gas well performance, and provides insights into history matching and optimization of hydraulic fracturing treatment design for shale gas production.
Natural gas productivity of eastern Devonian shale wells depends on the density and extent of natural fractures within the formation, the organic content of the shale matrix and the effective communication of the wellbore with the natural fracture system. Stimulation techniques are normally required to develop this communication. A strategy for testing stimulation techniques is currently being developed. The strategy for a geologic region involves the selection of the best stimulation technique for specific geologic conditions. This selection will be based on the thickness of the organic rich shale units within the formation (recognized as the source of gas) and the degree of fracture density (recognized as the reservoir) as controlled by various geologic elements.
Limited production history exists to support a strategy with certainty and confidence in the Devonian shale. However, data on initial openflow rates are available to compare explosive and hydraulic fracturing in both low and high frac density regions in the shale. These data have been accumulated on field tests conducted at random in DOE/industry projects. Tests included fracturing with displaced liquid explosives and also tests wherein cryogenic, water, and foam fracturing techniques have been used in both conventional and massive quantities. Analysis of this data shows that for regions of low fracture density, hydraulic fracturing is a slight improvement over borehole explosive stimulation treatments. Results from hydraulic fracturing may be further enhanced whenever retention time of the fracturing fluid in the formation is reduced. This suggests that low residual fracturing fluids such as foam or cryogenic treatments may be preferred for the low pressure shale reservoir. In regions of higher organic content, chemical explosives and hydraulic fracturing with cryogenic fluids are improvements over borehole explosive stimulation treatments, but the degree of improvement may not be justified by the required added costs. These observations constitute the early trend. Additional data and more detailed studies will be required in regions of different organic thickness and fracture density to reduce the uncertainty associated with this stimulation rationale.
Yan, Wei (China University of Petroleum) | Chen, Jianguo (The Second Daqing Drilling Company) | Deng, Jingen (China University of Petroleum) | Zhou, Yi (China University of Petroleum) | Wang, Kongyang (China University of Petroleum)
ABSTRACT: Hydraulic fracturing is the primary technology for shale gas development. The fracture toughness of shale is essential to estimate the initiation and propagation of fractures. The Mode-I fracture toughness of the Longmaxi Formation shale, which is taken from the Silurian strata in China Sichuan Basin, is tested in this paper by using the cracked chevron notched Brazilian disc (CCNBD) method. The experimental conditions include air dried shale and water saturated shale. The results show that there is a good quadratic polynomial relationship between the fracture toughness and tensile strength of both the air dried shale and the water saturated shale. The tensile strength can be used to estimate the fracture toughness of shale. The average tensile strength of water saturated shale is 5.3325 MPa, decreased about 35.58% compared to the air dried shale (8.2783 MPa).
As an emerging unconventional energy, shale gas has attracted much attention of many countries by its advantages of high energy intensity and little environmental pollution. The Longmaxi Formation of the Silurian strata in China Sichuan Basin (Figure 1) has a large exploration potential of shale gas (ARI, 2013). Shale gas, also called “Artificial Reservoir”, can only be extracted by means of mass artificial reservoir fracturing (Dong et al., 2012; Yan et la., 2016). At present, horizontal well volume fracturing has been the major method for producing shale gas. The initiation and propagation of hydraulic fractures in horizontal sections are mainly referred as the Mode-I fracture (Chen et al., 2015). Fracture mechanics states that when the stress intensity factor on the crack tip exceeds the rock fracture toughness, the rock will break, or fracture (Kahraman and Altindag, 2004). The previous researches show that one of the primary causes for rock materials failure is the forward extension of micro-fractures, and the main reason behind the micro-fractures’ extension attributes to the tensile stress acting on the fractures (Ouchterlony, 1998; Fowell, 1995; Zhang, 2002; Golshani et al., 2006 and 2007). Mode-I fracture toughness could be measured by using several methods(Li et al., 1999; Cowie and Scholz, 1992), such as the three point bending round bars (CB), short rod (SR) and cracked chevron notched Brazilian disc (CCNBD).
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 151597, "Measurements of Hydraulic-Fracture-Induced Seismicity in Gas Shales," by N.R. Warpinski, SPE, J. Du, SPE, and U. Zimmer, Pinnacle - A Halliburton Service, prepared for the 2012 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 6-8 February. The original paper was peer reviewed. See SPE Production & Operations August 2012, pages 240-252.
Hydraulic fracturing is essential for hydrocarbon extraction from both conventional and unconventional reservoirs. Recently, concern has developed regarding induced seismicity generated in association with multistage fracturing of horizontal wells in shale reservoirs. A review of thousands of fracture treatments that have been monitored microseismically shows that the induced seismicity associated with hydraulic fracturing is very small and not a problem under normal circumstances.
Hydraulic fracturing is important throughout the world. In unconventional reservoirs, such as ultralow-permeability shales, hydraulically fracturing a well is essential to obtain economic levels of production. Contrary to media and general-public perception, hydraulic fracturing is not a new technology, having been applied in the late 1940s. There also is a perception that hydraulic fractures are much larger than ever, but the massive hydraulic fractures performed in the 1970s were of similar size to fracture treatments conducted in horizontal wells today. Also, these early large treatments were performed in shales in the eastern United States (to prove up the resources in the Devonian shales of Appalachia) and in the western tight gas sandstones of the Rocky Mountains.
Results from thousands of monitored fractured treatments demonstrate that fractures will not propagate vertically thousands of feet and intersect potable-water sources. In all the shale basins studied, fractures remain several thousand feet below the deepest potable-water aquifer. Recently, however, there has been considerable attention focused on earthquakes associated with hydraulic fracturing. Microseismic monitoring is a valuable technology for assessing the earthquake potential of fracturing operations. The object of this study was the very large suite of microseismic measurements available from the major shale basins of North America. The study showed that earthquakes are not a threat in nor-mal situations.
It is well-understood that long-term injection of fluids into the deep subsurface can induce earthquakes. Many cases of minor earthquakes are documented that likely were induced by local injection operations, the most notable of which was the US Army’s injection of chemical waste into a 12,000-ft-deep interval at the Rocky Mountain Arsenal in Colorado in the 1960s. Similarly, geothermal injections are potential sources of induced seismicity, often because optimal geothermal sites are in areas where faults and tectonics are likely to be conducive to Earth movement. Other long-term injection operations, such as solution mining, water disposal, and waterfloods, are potential sources in areas where the geologic conditions are favorable.
Fakher, Sherif (Missouri University of Science and Technology) | Elgahawy, Youssef (University of Calgary) | Abdelaal, Hesham (University of Lisbon) | Imqam, Abdulmohsin (Missouri University of Science and Technology)
Abstract Enhanced oil recovery (EOR) in shale reservoirs has been recently shown to increase oil recovery significantly from this unconventional oil and gas source. One of the most studied EOR methods in shale reservoirs is gas injection, with a focus on carbon Dioxide (CO2) mainly due to the ability to both enhance oil recovery and store the CO2 in the formation. Even though several shale plays have reported an increase in oil recovery using CO2 injection, in some cases this method failed severely. This research attempts to investigate the ability of the CO2 to mobilize crude oil from the three most prominent features in the shale reservoirs, including shale matrix, natural fractures, and hydraulically induced fracture. Shale cores with dimensions of 1 inch in diameter and approximately 1.5 inch in length were used in all experiments. The impact of CO2 soaking time and soaking pressure on the oil recovery were studied. The cores were analyzed to understand how and where the CO2 flowed inside the cores and which prominent feature resulted in the increase in oil recovery. Also, a pre-fractured core was used to run an experiment in order to understand the oil recovery potential from fractured reservoirs. Results showed that oil recovery occurred from the shale matrix, stimulation of natural fractures by the CO2, and from the hydraulic fractures with a large volume coming from the stimulated natural fractures. By understanding where the CO2 will most likely be most productive, proper design of the CO2 EOR in shale can be done in order to maximize recovery and avoid complications during injection and production which may lead to severe operational problems.