The primary purpose of stimulating fractured shale reservoirs is the extension of the drainage radius via creation of a long fracture sand pack that interconnects with natural fractures thereby establishing a flow channel network to the wellbore. However, there is limited understanding of a successful method capable of stimulating Utica Shale reservoirs. Indeed, most attempts to date have yielded undesirable results. This could be due to several factors, including formation composition, entry pressure, and premature pad fluid leak-off. Furthermore, stimulation of Utica shale reservoirs with acid alone has not been successful. This treatment method leads to a fracture length and drainage radius less than expected resulting in poor well productivity. In this work, geological data is first examined for the reservoir. Laboratory data are then presented to address the unique mineralogy and mechanical properties of the Utica shale. The high percentage of acid soluble carbonate and dolomite suggests an acid treatment to lower entry pressures. This treatment can be the main stimulation of a vertical or horizontal well since natural fractures are present, or the acid breakdown can precede a gelled acid or proppant laden water frac or crosslinked fracturing fluid treatment. Experimental results reveal the impact of clays, potential generation of fines both siliceous and organic, acid solubility, low temperature biological activity, potential for scale generation and the prevalent problem of recovery of injected fluids. Acid solubility is presented vs. time and acid strength. Conductivity data is presented for gas fracs, matrix acidizing and proppant fracturing of the shale. The adsorption, as well as the regained relative permeability to gas is examined vs surfactant type to allow the selection of an additive package that will optimize fluid recovery and improve relative permeability to gas. Information obtained from this study can be used to optimize fracturing treatments of Utica shale reservoirs in the Appalachian Basin. Introduction As interest in drilling and producing shale reservoirs throughout North America increases due to the success of the Barnett, Woodford, and Fayetteville shales, numerous potential reservoirs that have previously been undeveloped are being examined for their potential. The organic-rich, low-permeability Upper Ordivician Utica Shale is one such reservoir that displays many attributes which may result in a commercially viable play of great areal extent. This interest is driven largely by increased natural gas prices and improved completion technologies. Indeed, there may be no better example of the role of technology in natural gas recovery than the Late Mississippian Barnett Shale of the Fort Worth Basin, which provides an analog for exploration of similar unconventional reservoirs throughout North America. Nevertheless, there is no universal production model method of stimulating each and every unconventional reservoir that exists. The Utica Shale compares favorably with such organic-rich units as the Middle Devonian Marcellus Shale of the Appalachian Basin and the Upper Cretaceous Lewis Shale of the Green River Basin (Table 1).

Summary The primary purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension and contact angle and provide leakoff control. However, many of these chemicals adsorb rapidly within the first few inches of the sandstone formations, reducing their effectiveness in deeper penetration. This phenomenon causes surfactants to adsorb or plate-out, reducing their effectiveness in post-fracturing fluid recovery. This study describes experimental and field-case studies of various surfactants used in the oilfield. Several different surfactants, including a nonionic ethoxylated linear alcohol, a nonyl phenol ethoxylate, an amphoteric, a cationic, and a microemulsion system were investigated to determine their adsorption properties when injected into a laboratory sandpacked column. A laboratory-simulated comparison study of commonly used surfactants and microemulsion was used to identify their leakoff and water-recovery properties from gas wells. Field data collected from Bradford, Balltown, and Speechley sandstone formations confirmed experimental sandpacked column and core-flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional surfactant treatments. Wellhead pressures, flowing pressures, and production data were collected and evaluated using a production simulator to show effective fracture lengths, damage surrounding the fractures, and drainage areas with various fluid systems. These investigations and presented case studies can be used to minimize formation damage. Introduction Surfactants or surface-active agents are predominantly used in hydraulic fracturing fluids to reduce emulsion tendencies between reservoir oil and treatment fluids. This problem is normally addressed by incorporating a nonemulsifier within fracturing fluids. However, when gas wells are stimulated with water-based fracturing fluids, fluid retention and a reduction in interfacial tension between the rock and the injected fluid are the key driving forces worthy of consideration for well cleanup. One of the continuing challenges in Appalachian Basin gas wells is post-fracturing fluid recovery caused by low-pressure reservoirs. This could be caused by the water-based fluid, creating fluid retention, interfacial tension between the injected fluid and the reservoir rock, or capillary end effect on and around the vicinity of the face of the fractured rock (Penny and Pursley 2005). To reduce these problems, commonly available surfactants are incorporated within the fracturing fluid to reduce surface tension. However, surfactants alone do not provide adequate water recovery properties for the reservoirs in the Appalachian Basin. Low temperature, pressure, and permeability of these reservoirs may be some of the major reasons that less than 50% of the treatment fluids can be recovered from gas wells through conventional methods (Penny and Pursley 2005). As illustrated in Fig. 1, it is possible that large quantities of injected fracturing fluids could be trapped in the area near the fractured proppant pack. When this condition occurs, higher water saturation adversely impacts the relative permeability, resulting in gas being trapped and thus significantly impairing gas production into the fractured face and ultimately into the wellbore. This condition along with capillary end effects eventually leads to longer swabbing times, well cleanups, and poor well productivity.

The primary purpose of surfactants used in stimulating Sandstone reservoirs is to reduce surface tension. Conventional surfactants adsorb rapidly within the first few inches of the sandstone formations, thus losing their effectiveness as the treating fluid leaks off. This results in trapped fluids and poor post fracturing fluid recovery. A surfactant solvent system in the form of a microemulsion can also be used to not only lower surface tension at very dilute concentrations, but alter contact angle and lower capillary pressure to further improve recovery. The unique microcells are also effective in controlling leakoff. This study describes the laboratory experiments and field case studies of various surfactants used in the oilfield. Several surfactants including an ethoxylated linear alcohol, a nonyl phenol ethoxylate and a microemulsion system were investigated to determine their adsorption properties when injected into laboratory sand packs. Laboratory studies were also conducted to compare the leakoff and water recovery properties from gas wells. Field data collected from Bradford and Speechley sandstone formations confirms experimental sand pack and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional surfactant treatments. Wellhead pressures, flowing pressures and production data were collected and evaluated using a production simulator to show effective fracture lengths and drainage areas with various fluid systems. Lab and field data collected in these studies from Appalachian Basin reservoirs illustrates that the addition of a microemulsion to a fracturing fluid exhibits significant advantages over the conventional surfactant treatments when water recovery, increased effective fracture length and well productivity are of concern to the operator. Introduction The primary objectives of this study include:Comparison studies of the microemulsion system with conventional surfactants commonly used in the oilfield to determine their adsorption properties into the proppant pack, leakoff, and water recovery.Gather experimental data comparing the effectiveness of conventional surfactants versus a microemulsion in regained permeability and fracture clean up test.Present case studies and production simulations where microemulsion treatments have improved water recoveries in treated gas wells in Bradford and Speechley formations. One of the continuing challenges in Appalachian Basin gas wells is post fracturing fluid recovery due to low pressure low permeability reservoirs. Most wells are stimulated with water based fracturing fluids and produce back less than half of the injected fluids even with the use of conventional surfactants that lower the air-water interfacial tension[1]. It must be assumed that these large quantities of fluid are trapped in the reservoir surrounding the wellbore and in the case of hydraulic fracturing the fluid is trapped in the area surrounding the fracture and within the fracture itself. This trapped fluid has a detrimental effect on the relative permeability, effective flow area, effective fracture lengths and without question impairs well productivity. There are more factors that influence the cleanup of injected fluids than simple air-water surface tension. An additional factor that is typically overlooked is the interfacial tension between the rock and the injected fluid which is of prime importance in dictating capillary pressure and capillary end effects in gas wells. This is even more important in low pressure areas where the available pressure may not overcome the capillary end effect leaving fluid trapped in the reservoir in a manner as illustrated in Figure 1[2].

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractThe primary purpose of stimulating fractured shale formations is to extend the drainage radius by creating a long fracture sand pack that connects natural fractures and increases flow channels to the wellbore. However, most of the fracturing pad fluid leaks off into natural fractures resulting in shorter effective fracture lengths and a significant damage zone surrounding the fracture. This is due in part to inadequate fluid loss control properties of the injected fluid and high capillary forces that retain fluid in the formation. Surfactants are used to lower high capillary forces and help well cleanup of the injected fluids. However, many of these additives adsorb rapidly within the first few inches of the shale formation, reducing their effectiveness and resulting in phase trapping of the injected fluid.In this work, laboratory data is presented for various fracturing fluids with different surface activity pumped into the Rhinestreet Shale. Recent fracture treatments have been successful utilizing a slick water treatment consisting of water and dry polyacrylamide polymer with and without surfactants. Commonly used surfactants as well as a microemulsion system are evaluated in this study.Laboratory data is presented illustrating how a microemulsion accelerates post fracturing fluid cleanup in tight shale cores. Addition of microemulsion to the fracturing fluid also results in lowering pressure to displace injected fluids from low permeability core samples and proppant packs. When microemulsion is incorporated at 2 gpt within the fracturing fluid; the relative permeability to gas is increased substantially while water saturation is decreased. This alteration of the fracturing fluid effectively lowers the capillary pressure and capillary end effect associated with fractures in low permeability reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the fracture, hence longer effective fracture lengths.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe primary purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension of the fracturing fluid, decrease interfacial tension between injected fluid and reservoir rock and increase post-fracturing fluid recovery. However, many of these chemicals when injected at high pressures adsorb rapidly into the sandstone formation, reducing their effectiveness in post fracturing fluid recovery.This study describes simulated laboratory experiments and case histories of various surfactants used in the oilfield. Several different surfactants including ethoxylated linear alcohol, nonyl phenol ethoxylate and a microemulsion system were investigated to determine their adsorption properties when injected into a sand packed column. A laboratory simulated comparison study of these surfactants versus a microemulsion system was used to identify their water recovery properties from gas wells.Field data collected from Benson, Balltown, Injun, and Speechley Sandstone formations confirm experimental sand packed column and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional nonemulsifying surfactant treatments. Case histories reported from several gas wells stimulated in the Appalachian Basin illustrate the advantages microemulsions have over conventional surfactant treatments when faster cleanup, increased post fracturing fluid recovery and well productivity are of concern to the operator.