The vast majority of gas wells in the nation's emerging gas plays do not naturally produce gas at sufficient rates to make the well economical. It is typically necessary to stimulate the well to increase conductivity between the wellbore and high-permeability zones and/or natural fracture systems. The most prevalent stimulation method, hydraulic fracturing, generally involves inducing artificial fractures in the reservoir through injection of high-pressure water. Sand is also injected and provides a means of propping the fractures open once the water is retrieved.

In many settings however, hydraulic fracturing is ineffective or even damaging, because the water causes shale grains prevalent in marginal reservoirs to swell, thereby reducing reservoir permeability and/or porosity. Research conducted for NETL is evaluating various new and innovative stimulation fluids that avoid this problem. For example, Petroleum Consulting Services has demonstrated the potential of well stimulation that uses liquid CO2 in place of water. Like water, the liquid CO2 can effectively carry sand into the induced fractures; however, unlike water, the liquid carbon dioxide reverts back to a gas at reservoir pressures, leaving only sand in the induced fracture system. Although the CO2 sand stimulation is costly, well clean-up costs are reduced because there is no need to recover the injected water. Most importantly, well productivity is enhanced because there is no permeability-damaging reaction between the water and clay minerals occurring naturally in the formation.

In cooperation with NETL, RealTimeZone, Inc, developed new reservoir stimulation processes that combines fracture fluids (CO2 & N2) with proppant and gels downhole to create a composite fluid. The resulting fracturing fluid is similar to surface-mixed foam fracturing treatments, but with advantages including better control of proppant concentration and placement, and lower cost. RealTimeZone also developed a tracer diagnostic tool to evaluate the fracture stimulation process. The system is intended to give operators on the surface virtually instantaneous readings on the progress of the fracturing operation allowing them to change or halt the process before damage to the reservoir occurs.

Under DOE sponsorship, Pinnacle Technologies, Inc., in conjunction with Sandia National Laboratory, is developing and testing an advanced system which will address limitations in hydraulic fracture mapping technology and provide industry with an improved system to measure created fracture geometry. The improvements will lead to wider and more effective application of hydraulic fracture mapping. Microseismic and tiltmeter hydraulic fracture mapping are proving to be very useful technologies allowing producers to optimize individual fracture treatments and field development. Development of a combined microseismic receiver-tiltmeter system eliminating the need for two observation wells will help reduce costs.

Many operators today are using simple water frac treatments to stimulate production from tight sand formations. Water is preferred because it is generally cheaper than gel-based treatments. Most fracture simulation models however, were not designed for simple water frac treatment. The University of Texas at Austin and Anadarko Petroleum Corp. have investigated multiple geomechanical and petrophysical methods to analyze data from fracture treatments from the tight gas sands in the Bossier Sand play in East Texas. This information was used to update current gel-based models to better predict proppant transport, fluid leakoff, and fracture cleanup and performance of water frac processes. The improved model was then used to develop guidelines for selection of fracturing fluids and optimization of the future fracture field tests. These fracture field tests were applied to the Cotton Valley Sands, a section very similar to the Bossier Sands, in Carthage Field.