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As part of a Department of Energy (DOE)-sponsored program, an optimal thermodynamic pathway to transform natural gas (NG) into pressurized NG suitable for use as the internal phase in a foamed fracturing fluid has been already developed. Using NG foamed fracturing fluids reduces the enormous water requirements for stimulation by as much as 60% to 80% and poses benefits for productivity in water-sensitive formations. This study aims to extend the investigation to characterize the hydraulic fracture geometry and quantify the expected production when using an NG foam fracturing fluid. Using validated models, we provide a comparative analysis to determine the advantages of using natural gas foams relative to conventionally used slickwater, linear gel, and crosslinked fluid.
A full 3D reservoir model in a Duvernay Shale formation was constructed. Fundamental laboratory and pilot field tests data was collected for the NG foam fluid properties for numerical modeling. Rheology, friction, and leakoff properties of the fracturing fluids were incorporated in creating a numerical model. A 3D-complex hydraulic fracture simulation model incorporating 1D and 2D particle transport models were used. A numerical reservoir simulation for different sensitivity scenarios was incorporated for fracture modeling and gas production evaluation. Owing to lower density than conventional liquid column, the NG-foamed fluids are likely to result in higher surface pressure.
A reduced pump rate with NG foamed fracturing fluid leads to a lower frictional pressure loss in tubing, without compromising the ability to place the desired amount of proppant in the formation. The non-Newtonian shear-thinning NG-foamed fracturing fluid exhibits a higher, effective viscosity that enables effective transport of the proppant. Modeling results indicate that the overall fracture geometry and proppant placement is much better for NG-foamed fluids than high-volume slickwater needed to pump the same amount of proppant for well spacing and a field development plan. The simulated production performance for medium-viscosity fluids such as NG-foamed fluid, linear gel, and high-viscosity slickwater, is better than that of low-viscosity slickwater or high-viscosity crosslinked gel fluids. A low-viscosity fluid results in proppant settling and dunning, resulting in lower conductive height of fractures while the high viscosity treatment uses less fluid, so the surface area created is less and there is potential for height grow out of the target formation.
Beck, Griffin (Southwest Research Institute) | Nolen, Craig (Southwest Research Institute) | Hoopes, Kevin (Southwest Research Institute) | Krouse, Charles (Southwest Research Institute) | Poerner, Melissa (Southwest Research Institute) | Phatak, Alhad (Schlumberger) | Verma, Sandeep (Schlumberger)
Abstract Foams have been used as hydraulic fracturing fluids to reduce water usage and minimize the potentially deleterious impact on water-sensitive formations. Traditionally, carbon dioxide (CO2) and nitrogen (N2) have been used as the internal phase in these foamed fluids. Hydraulic fracturing with natural gas (NG) is a relatively inexpensive option, particularly if NG produced from the wellhead can be used without significant processing. In an ongoing program sponsored by the US Department of Energy (DOE), an alternative fracturing process is being developed that uses NG-based foam. Previously, the optimal thermodynamic pathway was identified to transform wellhead NG into pressurized NG suitable for use as the internal phase in a foamed fracturing fluid. Recent work has focused on preparing a NG-based foam at surface conditions typically encountered in hydraulic fracturing and measuring the stability and rheological properties of the foam. In addition, the transient response of the foam during fracture initiation was simulated using a fast-acting solenoid valve. A single base-fluid mixture was prepared by combining a commercially available viscosifier and foaming surfactant with water. The base fluid was then injected into a tee using a water pump. Simultaneously, liquefied natural gas (LNG) was pressurized using a cryogenic pump, vaporized using a heat exchanger, and injected into the tee to mix with the base fluid and generate foam. The foam then flowed through approximately 300 ft of 0.312-in. inside diameter (ID) tubing equipped with pressure transducers at several locations. The test fixture included a sight glass to visually inspect the quality of the foam. This paper reports on findings related to foam stability and rheology and compares these results to previous studies on foamed fracturing fluids.
Beck, Griffin (Southwest Research Institute) | Bhagwat, Swanand (Southwest Research Institute) | Day, Carolyn (Southwest Research Institute) | Gordon, Emilio (Southwest Research Institute) | Daeffler, Chris (Schlumberger) | Malpani, Raj (Schlumberger) | Verma, Sandeep (Schlumberger) | Chaves, Leo (Chevron) | Comeaux, Bruce (Chevron) | Chrusch, Larry (Chevron) | Naik, Sarvesh (Chevron) | Renk, Joseph (National Energy Technology Laboratory)
Nitrogen (N2) and Carbon Dioxide (CO2) foams have been used as hydraulic fracturing fluids for several decades to reduce water usage and minimize damage in water-sensitive reservoirs. These foam treatments require gases to be liquefied and transported to site. An alternative approach would be to use natural gas (NG) that is readily available from nearby wells, pipelines, and processing facilities as the internal, gaseous phase to create a NG-based foam. Hydraulic fracturing with NG foam is a relatively inexpensive option, makes use of an abundant and often wasted resource, and may even provide production benefits in certain reservoirs. As part of an ongoing development project sponsored by the Department of Energy (DOE), the surface process to create NG foam is being developed and the properties of NG foam are being explored. This paper presents recent results from a rigorous pilot-scale demonstration of NG foam over a range of operating scenarios relevant to surface and bottomhole conditions with a variety of base-fluid mixtures.
The NG foams explored in these investigations exhibited typical, shear-thinning behavior observed in rheological studies of N2- and CO2-based foams. The measured viscosity and observed stability indicate that NG foams are well suited for fracturing applications. Like other foams, NG foam exhibits sensitivity to operating temperature characterized by a decrease in apparent viscosity as temperature increases. Rapid foam breakdown was observed at significantly elevated temperatures exceeding 290°F. In addition to fluid characterization, these investigations also yielded several key lessons that should be applied to future field demonstrations of NG foam.
Abstract The use of foam for mobility control is a promising mean to improve sweep efficiency in EOR. Experimental studies discovered that foam exhibits three different states (weak foam, intermediate foam, and strong foam). The intermediate foam state is found to be unstable in the lab whereas the weak- and strong-foam states are stable. The model of Kam (Colloids Surfaces A, 2008) is the only mechanistic foam model that can fit a variety of steady-state experimental data including multiple steady states. This model is modified from a previous mechanistic foam model to resolve the intrinsic instability of the strong-foam state. Simple finite-difference simulations have found that an arbitrary perturbation grows for the unstable intermediate foam but diminishes for the strong- and weak-foam states. The issue of the stability of foam states, especially the strong-foam state, is a serious concern in application of foam in EOR. Instabilities may rule out one or more states and consequently have considerable effect on reservoir sweep efficiency and injection pressure. Here, for the first time the stability of the various foam states is investigated by a semi-analytical stability-analysis method. We demonstrate the instability of most intermediate states, consistent with the laboratory observations. However, fine analysis reveals a slight instability of the strong-foam state. We show that the diffusion, whether introduced artificially by the finite-difference scheme or representing physical dispersion, damps this slight instability. We obtain good agreement with finite-element simulations with and without diffusion.
In this paper, we discuss arguments for the use of these fluids beyond the under-pressured, dry gas reservoirs where they are already favored, using a model developed at the University of Texas at Austin. The simulation study uses reservoir conditions based on available information for the Utica, which was chosen because it is a liquid-rich shale of current interest. Introduction This paper explores the extension of foam-based fracturing fluids beyond under-pressured, dry gas reservoirs that have been their typical targets (Hurst 1972; Bleakley 1980; Grundman 1983; King 1985; Ward 1986; Harris 1992; Gupta and Bobier 1998). The fundamental motivations of this approach are to reduce water consumption and to decelerate production declines, in other words to pursue a more "sustainable" approach, not just from a strictly environmental point-of-view but also by extending the productive lifetime of each well. By "foam-based fracturing fluids" we mean, in general, fluids in which an industrial gas such as CO