Field Case Studies: Damage Preventions Through Leakoff Control of Fracturing Fluids in Marginal/Low-Pressure Gas Reservoirs

Abstract

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.

Surface Energy of North American Shales and its Role in Interaction of Shale with Surfactants and Microemulsions

“…Figure 3 also illustrates that under certain conditions microemulsions may produce higher contact angles on shale surface as compared to the surfactant solutions of the same concentrations. This has also been illustrated in previous laboratory study [8], as well as estimated from the capillary pressure measurements [5]. As seen in Figure 3, the extent of impact of microemulsion on contact angle depends on the solvent-to-water ratio in microemulsion and especially large in the case of balanced microemulsion with O/W ~ 1.…”

“…In recent years a significant number of publications describing successful use of microemulsions and surfactant solutions for enhancing fluid flowback and increasing gas production rates have appeared in the literature [1][2][3][4][5]. The benefits of surfactants and microemulsions are related to their surface activity, which is revealed as their ability to lower surface tension and contact angle on air/water interfaces and in turn influence capillary pressure, p cap , which is given by a wellknown equation , cos 2 r p L cap θ γ = ( 1 ) where γ L is the liquid surface tension, θ is contact angle at three-phase contact line, and r is the radius of pores.…”

ME Surfactant Increases Production in the Codell Formation of the DJ Basin

“…A NE is typically employed to balance the oil/water interfacial tension (Penny et al 2006). The use of water-based fluids in gas reservoirs can create other problems, such as fluid retention, interfacial tension between the injected fluid and the reservoir-rock or capillary-end effects around the fracture face (Pakinat et al).…”

“…ME appears as a single, optically clear phase and is stable in high dilutions of both oil and water (0.1-0.5% by volume) as it is added to either water or oil-based fracturing fluid (Penny et al 2006). MEs are capable of many functions including reduced surface/interfacial tension in aqueous fluids (less than 25 dynes/cm compared to 72 dynes/cm for fresh water) (Dean 1969).…”

Post-Fracturing Fluid-Recovery Enhancement With Microemulsion

“…Though laboratory testing in cores between 1 and 8.5mD failed to show a significant difference between the microemulsion and surfactant, the wells fractured with the microemulsion additive consistently outperformed those fractured previously in terms of returned treatment fluids and incremental production. Paktinat et al (2006) wrote that the use of fracturing fluids with microemulsion in unconventional tight gas reservoirs can help increase production by increasing the relative permeability to gas in the area surrounding the fracture. Our study shows that similar benefits can also be achieved in depleted gas reservoirs with permeabilities greater than 1 mD, even if the benefits can not be clearly demonstrated under laboratory conditions.…”