The goal of this project is to develop and demonstrate the use of readily-available natural gas collected at the wellhead as a primary fracturing fluid. The work proposes to develop, validate, and demonstrate affordable non water-based and non CO₂-based stimulation technologies, which can be used instead of, or in tandem with, water-based hydraulic fracturing fluids to reduce water usage and the volume of flowback fluids. The process will use natural gas at wellhead supply conditions and produce a fluid at conditions needed for injection.

Southwest Research Institute (SwRI), San Antonio, TX 78238
Schlumberger Technology Corporation (SLB), Sugar Land, TX 77478
Chevron Energy Technology Corporation, Houston, TX 77002

Fracturing fluids are composed of approximately 90 percent water. One of the principal drawbacks to hydraulic fracturing is its excessive water use. Each application of hydraulic fracturing consumes between three and seven million gallons of water. During the fracturing process, some of the fracturing fluid is permanently lost and the portion that is recovered is contaminated by both fracturing chemicals and dissolved solids from the formation. The recovered water, or flowback, represents a significant environmental challenge because it must be treated before it can be reintroduced into the natural water system. Although there is some recycling of flowback fluids for future fracturing, the majority of the flowback water is hauled from the well site to a treatment facility or to an injection well for permanent underground disposal. 

To mitigate these issues, an optimized, lightweight, and modular surface process involving natural gas compression, and injection will be developed and tested to replace water as a cost-effective and environmentally-clean fracturing fluid. Using natural gas produced from the well for hydraulic fracture stimulation will result in a near zero consumption of water. The gas is combined with a portion of water to generate foam which is injected as a fracturing fluid; it will mix with newly-released formation gas and both will be extracted to the surface. This greatly reduces the collection, waste, and treatment of large amounts of water, and reduces the environmental impact of transporting and storing the fracturing fluid.
 

The primary benefit of this program is the ability to utilize natural gas as the primary fracturing fluid, thus, reducing water use. Traditional fracturing operations throughout the U.S. use a substantial amount of water, much of which is lost permanently or is difficult and expensive to decontaminate. In this research, natural gas will be readily obtained, either from the wellhead (produced gas) that is typically located near the well site or from nearby processing facilities. This technology will eliminate much of the environmental impact associated with transporting fracturing fluids to and from the well site. The process does not depend on large amounts of water, which will minimize the flowback water disposal problem associated with traditional hydraulic fracturing. Once the well begins producing natural gas, the natural gas that was used as the primary fracturing fluid can be introduced back into the pipeline. 

There are many significant benefits to the process, some of which are: 

• Reduction of waste products 
• Less separation of water and gas required 
• Decrease in the formation of emulsions, which will result in fewer blockages in the formation, and thus, improved gas flow 
• Less clay swelling, which will result in better well production 
• Onsite pressurized natural gas can be used for running field equipment 
• Significant reduction in water transport, resulting in less vehicular traffic, emissions, and road wear 

• Foamed fluids were used to fracture shale samples to investigate the impact of fluid compressibility on fracture propogation.
• Reservoir models were generated to exlore the impact of natural gas-based foams on well production. 
• Natural gas compression process models have been modified to include natural gas mixtures as the primary working fluid. 
• Four natural gas mixtures have been selected. These mixtures will be used to update the current compression process models and in closed-loop rheology tests.
• Data generated from the budget period 3 tests have been analyzed, and foam rheology data has been reported.
• Three additional aqueous phase fluid compositions were tested using the pilot scale facility to determine if a stable, natural-gas-based foam could be generated from additional mixtures not explored in the budget period 2 work. 
• A foam mixing apparatus that mimics mixing conditions achievable in the field was designed and tested at the pilot scale facility.
• The pilot scale test facility was modified to allow for improved rheology testing capabilities.
• Data generated from the budget period 2 laboratory tests have been analyzed and initial foam rheology data has been reported. 
• The budget period 2 laboratory tests were completed.
• The budget period 2 test stand was constructed, and sub-systems were commissioned.
• Equipment for the budget period 2 laboratory test was ordered and received. 
• The test matrix for the budget period 2 testing was finalized. 
• A conceptual design for the laboratory testing for budget period 2 was completed. 
• The test objectives for budget periods 2 and 3 were refined. This was contingent upon the top cycle selected and the results of the work in the current year. 
• A literature review was performed on natural gas rheology to identify what work had been done and any technology gaps. 
• The top cycle (direct compression system) was selected using the defined metric system. 
• The metric scoring system was expanded to consider cost, maintenance, operation expenses, and mobility. 
• Detailed analyses were performed on the top three cycles. This included updating the thermodynamic models to include the commercial equipment design values, constructing site layouts plans for each cycle to understand how the equipment would be arranged and transported to the well site, and estimating the cost to construct each of the three cycles. 
• Commercial equipment was identified for the major components in each of the top three cycles.
• An initial selection of the top three concepts was completed. 
• A comprehensive metric and scoring system was developed to rank the concepts for selection of the top two or three concepts. 
• Commercially available equipment was surveyed to determine if the cycle design was realistic.
• The thermodynamic cycle for each concept was modeled to determine the minimum power usage and the type of equipment necessary for the cycle.
• Several cycle concepts for processing low-pressure natural gas to a high-pressure natural gas for fracturing were developed.

Project work concluded in March 2021 at the end of the final budget period. Work in budget period 5 included the design and operation of a small foam generation apparatus that was used to fracture samples of shale. These tests were conducted in an effort to determine whether fluid compressibility impacts fracture morphology. Additionally, reservoir models were created to investigate whether the use of natural gas-based foams impacts well productivity compared to typical, incompressible fracturing fluids.    

$2,669,975

$668,005

NETL – Joseph B. Renk III (joseph.renk@netl.doe.gov or 412-386-6406)
SwRI – Griffin Beck (griffin.beck@swri.org or 210-522-2509)

Development and Field Testing Novel Natural Gas Surface Process Equipment for Replacement of Water as Primary Hydraulic Fracturing Fluid (Oct 2020)
Presented by Griffin Beck, Southwest Research Institute, Hydraulic Fracturing Technologies Project Review Meeting, October 14, 2020

Development and Field Testing Novel Natural Gas Surface Process Equipment for Replacement of Water as Primary Hydraulic Fracturing Fluid (Aug 2017)
Presented by Griffin Beck, Southwest Research Institute, 2017 Carbon Storage and Oil and Natural Gas Technologies Review Meeting, Pittsburgh, PA

Development and Field Testing Novel Natural Gas Surface Process Equipment for Replacement of Water as Primary Hydraulic Fracturing Fluid (Aug 2016)
Presented by Griffin Beck and Sandeep Verma, Southwest Research Institute, 2016 Carbon Storage and Oil and Natural Gas Technologies Review Meeting, Pittsburgh, PA