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Abstract The development of shale reservoirs has grown significantly in the past few decades, spurred by evolving technologies in horizontal drilling and hydraulic fracturing. The productivity of shale reservoirs is highly dependent on the design of the hydraulic fracturing treatment. In order to successfully design the treatment, a good understanding of the shale mechanical properties is necessary. Some mechanical properties, such as Young's modulus, can change after the rock has been exposed to the hydraulic fracturing fluids, causing weakening of the rock frame. The weakening of the rock has the potential to increase proppant embedment into the fracture face, resulting in reduced conductivity. This reduction in conductivity can, in turn, determine whether or not production of the reservoir will be economically feasible, as shale rocks are characterized by their ultra-low permeability, and conductivity between the reservoir and wellbore is critical. Thus, shale reservoirs are associated with economic risk; careful engineering practices; and a better understanding of how the mechanical properties of these rocks can change are crucial to reduce this risk. This paper discusses various laboratory tests conducted on shale samples from the Bakken, Barnett, Eagle Ford, and Haynesville formations in order to understand the changes in shale mechanical properties, as they are exposed to fracturing fluids, and how these changes can affect the proppant embedment process. Nanoindentation technology was used to determine changes of Young's modulus with the application of fracturing fluid over time and under high temperature (300 °F) as well as room temperature. Mineralogy, porosity, and total organic content were determined for the various samples to correlate them to any changes of mechanical properties. The last part of the experiments consisted of applying proppants to the shale samples under uniaxial stress and observing embedment using scanning acoustic microscope. The results of this study show that maximum reduction of Young's modulus occurs under high temperature and in samples containing high carbonate contents. This reduction in Young's modulus occurs in "soft" minerals as well as the "hard" rock-forming minerals. This reduction of modulus can cause the effective fracture conductivity to decrease significantly.
Sayed, Mohammed A. (Aramco Services Company: Aramco Research Center—Houston) | Al-Muntasheri, Ghaithan A. (Aramco Services Company: Aramco Research Center—Houston) | Liang, Feng (Aramco Services Company: Aramco Research Center—Houston)
Abstract The ever-increasing international energy demands require exploration of new fossil energy resources. Unconventional oil and gas have received a great deal of attention in recent years as the technological advancements have made their production possible and more economical. Most of the shale developments took place in North America where the learning curve is being developed. Although shales still require lots of understanding and more advanced technologies, a substantial experience has been developed in North America. This paper presents an effort to summarize the current experience in shales of North America from different angles: rock mechanics, rock/fluids interaction, gas flow mechanisms through shale rocks, proppant embedment and water recovery after shale fracturing. Three prospective areas for unconventional gas were found in the Kingdom of Saudi Arabia: in the Northwest, South Ghawar and condensate-rich shale gas in the Rub' Al-Khali area. The main targeted formations for unconventional natural gas are: the Ordovician Sarah, Silurian Qulibah, Qusaiba hot shale, Devonian Jauf and Permian Unayzah formations. The Qusaiba shale is located at depths of 7,500 to 20,000 ft throughout Saudi Arabia's basins. The Qusaiba Hot Shale in the Northwest area is relatively thick and it is considered to be the richest in all possible source rocks with a maximum total organic content of 6.15%. Shales are composed of: kerogen, rock matrix and natural fractures. The mineralogy of shale varies from one field to another. Literature has confirmed that for Haynesville shale, the rock becomes more ductile with the increase in its clay content. Similar trends were seen for Lower Bakken shale. While other shale reservoirs, like Eagle Ford, Barnett and Middle Bakken are harder since they contain more quartz and calcite. The exposure of these clay-sensitive rocks to fracturing fluids does change their rock mechanical properties. This has been confirmed in literature where Middle Bakken shale lost 52% of its Young's modulus after exposure to 2 wt% KCl slickwater at 300°F for 48 hours. The use of slickwater in fracturing represents a major challenge as it consumes huge volumes of this valuable resource. Recycling of produced water has been attempted in North America in Marcellus. An average amount of 3 to 8 million gallons of water are used in fracturing one well in Marcellus shale formation. In one application, re-use of the flowback water resulted in 25% reduction in the fresh water volumes and it reduced the cost of disposing produced water by 45 to 55%. The paper presents a summary of all of these findings from North America. A comprehensive understanding and analysis on unconventional reservoirs is required for the Middle Eastern reservoirs.
Abstract Shale oil and gas developments have been growing dramatically in the U.S. since the successful development of the Barnett shale in the early 2000's. The industry was able to unlock the Barnett shale by coupling the technologies of both horizontal drilling and hydraulic fracturing. The experience stimulated the spread of this method to other fields which eventually led to the recent U.S. production boom. However, numerous underperforming wells draw attention to the importance of completion optimization to maximize hydrocarbon production from shale reservoirs. Several approaches for completion optimization have been developed; however, fracture conductivity is usually sacrificed to minimize the operational cost. The objective of this paper is to provide a comprehensive review that highlights the importance of fracture conductivity to hydrocarbon production from shale reservoirs and its potential roles in the fracture design process. The reviewed simulation, laboratory, and field studies reveal the importance of improving fracture conductivity to maximize the reserve and well production performance in different shale formations. Reliance of well production on fracture conductivity is explained by its severe reduction at downhole conditions, in addition to, the improved effective formation permeability by the effect of the induced microfracture networks. The factors affecting the fracture conductivity at downhole conditions and its calculation complexity are explained. The review also demonstrates the adverse effect of water on fracture conductivity in shale formations, through shale softening and proppant embedment mechanisms. The different approaches to select the fracturing fluid additives for an improved fracture conductivity are summarized in this review. To minimize the damage to the formation and the fracture conductivity, the use of water-alternative energized fluids is discussed. This paper improves the understanding of the main factors affecting the success of shale hydraulic fracturing treatments. Hydraulic fracturing is the main key to ensure an optimum completion process which helps to maximize the production from unconventional shale oil and gas reservoirs.
Abstract For low-permeability formations, such as oil- and gas-bearing shales, hydraulic fracturing stimulation is necessary to obtain commercial production. One of the key parameters for helping ensure successful stimulation and prolonged production is the proper selection of stimulation fluid. The selection and optimization of the fracturing fluid is greatly dependent on reservoir rock properties as well as formation softening attributed to fluid-formation interaction. A slickwater treatment fluid has often been adopted in the past in tight shale plays for creating a complex fracture network for maximum production yield. Most often, the slickwater recipe is driven by formation fluid sensitivity analysis (e.g., effect of fresh water, salt, or acids on formation). While this might work for some formations, the rock mechanical properties, such as Young's modulus and Poisson's ratio, will determine the fracability and whether it is advantageous to use a slickwater, linear, or crosslinked gel. Similarly, analysis of formation softening using Brinell hardness testing and proppant embedment testing will help ensure the formation does not completely close on treatment completion and will have conductive flow channels. The formation rock, proppant, and fracturing fluid interaction can also result in diagenetic growth on proppant and formation faces, resulting in formation softening and large decrease in fracture conductivity. This paper describes test processes involving fluid sensitivity tests, formation softening, and rock mechanical tests, and compares data from a few representative shales to demonstrate the impact of choosing the proper fluid formulation for hydraulic fracturing. This paper focusses on careful optimization of the stimulation fluid based on rock parameters to help ensure prolonged production in tight-oil and gas shale plays.
Abstract For low-permeability formations, such as oil- and gas-bearing shales, hydraulic fracturing stimulation is a requisite to obtain commercial production. One of the key parameters for ensuring successful stimulation and prolonged production is the proper selection of stimulation fluid. The selection and optimization of the fracturing fluid is greatly dependent on the reservoir rock properties as well as the formation softening resulting from fluid-formation interaction. In the past, slickwater treatment fluids often were adopted in tight shale plays for creating a complex fracture network for maximum production yield. Most often, the slickwater recipe is driven by formation fluid sensitivity analysis (e.g., effect of fresh water, salt, or acids on the formation). While this might work for a few formations, the rock mechanical properties, such as Young's modulus and Poisson's ratio, will determine the fracability and whether it is advantageous to use slickwater, linear gel, or crosslinked gel. Similarly, formation softening analysis using a Brinell hardness test and proppant embedment test will ensure that the formation does not close upon fluid treatment and will have conductive flow channels. This paper discusses the impact of different types of fracturing fluids on different shale formations. The paper also discusses processes involving fluid sensitivity tests, formation softening, and rock mechanical tests and shows their influence on the choice of the proper fluid formulation for hydraulic fracturing through data from a few test samples. The formation rock, proppant, and fracturing fluid interaction can also cause diagenetic growth on proppant and formation faces, resulting in formation softening and a large decrease in fracture conductivity. This paper focusses on careful selection of the stimulation fluid based on rock parameters to ensure prolonged production in tight oil and gas shale plays.