Field Studies of Drilling and Completion Fluids to Minimize Damage and Enhance Gas Production in Unconventional Reservoirs

Abstract

Field data and lab data are presented for various fluids pumped in low perm shales, coalbed methane and tight sandstone reservoirs. Commonly used surfactants, alcohols as well as a microemulsion system (ME) are evaluated. Lab data is presented that illustrates the cleanup of injected fluids in tight gas cores. Damage mechanisms are shown to be phase trapping and high capillary pressures. The microemulsion additive results in lower pressures to displace injected fluids from low permeability core samples over conventional surfactant and methanol treatments. The observed enhanced relative permeability mechanism is the alteration of the rock-fluid interfacial tension or contact angle. It is demonstrated that this alteration effectively lowers the capillary pressure and capillary end effect associated with wellbores and fractures in low perm reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the wellbore following drilling and hydraulic fracturing. Over 300 wells were evaluated that were drilled and/or fracture treated with various fluid combinations in the Barnett, Fayetteville and Appalachian basin shales. Some 200 wells are examined in the San Juan Basin and other low perm areas such as the Pieance Basin, Uinta, Vicksburg and Cotton Valley. Drilling examples are shown for several horizontal wells. The addition of the microemulsion to fracturing treatments has resulted in more than 50 to 100% increases in load recoveries and gas production. Production analysis of horizontal wells drilled and cleaned up with the microemulsion shows a doubling of production over offsets. Pressure analysis of fractured wells shows that the damage factor is reduced by a factor of 2 with the inclusion of ME. This is a result of a combination of reduced depth of invasion, a higher relative perm in the invaded zone and/or longer effective frac lengths. Introduction The primary objectives of this study include:Examine factors that govern the cleanup of injected drilling and fracturing fluids.Present Case studies in several unconventional reservoirs comparing various surfactants in drilling and fracturing treatments looking at water recovery and oil and gas production. Commonly used fluids in unconventional resources are water with friction reducer and surfactant typically to lower surface tension. There are several factors that govern cleanup of hydraulic fractures. In addition to simple air-water surface tension, a 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 becomes important available pressure does not overcome the capillary end effect leaving fluid trapped in the reservoir in a manner illustrated in Figure 11.

CO2 Foam as an Improved Fracturing Fluid System for Unconventional Reservoir

“…Prior to the implementation, it is important to investigate the performance of fracturing fluid at reservoir conditions. The measurement of fundamental properties of the used foaming agent such as interfacial tension and contact angle that are the basis for reducing capillary pressure are also essential to perform [89,90]. Additionally, the adsorption of surfactant as a foaming agent is equally important to study in order to estimate the chemical loss in the reservoir during the recovery process.…”

“…Furthermore, it has been reported that several field pilot tests were conducted to check the performance of surfactant for fracturing applications. Most of the pilot tests were conducted in the Barnett and Marcellus shales utilizing conventional surfactants which include nonionic alcohol ethoxylate surfactants and amphoteric and cationic surfactants [89]. The water recovery using conventional surfactants has been reported to achieve approximately 60% (an average of 3 wells) [89].…”

“…Most of the pilot tests were conducted in the Barnett and Marcellus shales utilizing conventional surfactants which include nonionic alcohol ethoxylate surfactants and amphoteric and cationic surfactants [89]. The water recovery using conventional surfactants has been reported to achieve approximately 60% (an average of 3 wells) [89]. Barnett shale is considered notorious for retaining water.…”

“…Barnett shale is considered notorious for retaining water. Another case study was conducted considering a conventional surfactant and only 2300 bbl of water was recovered out of injected 6430 bbl giving about 28% recovery [89]. A nanofluid has also been employed in fracturing job to reduce the chemical adsorption whereby the recovery of injected water reached about 40% in this case [91,92].…”

Synergistic Effect of Sodium p-Perfluorononenyloxybenzenesulfonate and Alkanolamide Compounding System Used as Cleanup Additive in Hydraulic Fracturing

“…Hydraulic fracturing technology is the most important stimulation treatment for developing unconventional hydrocarbons. Water-based fracturing fluid is the most commonly used fluid, such as guar gum fracturing fluid, slick-water fracturing fluid, clean fracturing fluid, and so on. , However, it is reported that usually only 5–50% of the injected fluid can be successfully returned to the ground. These retained fluids (or so-called filtration loss fluid, or invading fluid) often cause greater damage to the reservoir matrix permeability, such as water-sensitivity damage and water-locking damage. − Water-sensitivity damage can be improved by adding clay stabilizer into the fracturing fluid, while well shut-ins after hydraulic fracturing and adding cleanup additives are effective for water-locking damage. − The effectiveness of well shut-ins after fracturing depends on the reservoir physical properties.…”