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While there are many decades of experience with hydraulic fracturing in the petroleum industry, the recent exposure of the general public to this technology, particularly as practiced with large volume water fractures in the gas shales, has resulted in considerable fear and misunderstanding of what is occurring downhole. Fortunately, the industry has been studying the problem of fracture height growth for several decades and has been monitoring fractures with tiltmeters for two decades and with microseismicity for over one decade. This compendium of knowledge and measurements shows that the common practice of multi-stage stimulations of shale reservoirs in horizontal wells is not a threat to groundwater via fracture pathways.
Perhaps the most compelling evidence for the safety of fracturing in a deep shale environment comes from microseismic fracture mapping. This case is of particular interest because of the large volumes of water injected into the reservoir during the stimulation. Many thousands of fractures have been mapped in these reservoirs and the heights of the fractures are well characterized. When presented for an entire basin, the amount of growth as a function of initial depth can be displayed and correlated with groundwater depths. In all cases, the fractures remain many thousands of feet away from the groundwater. It is found that fracture height can be quite variable, but even in the reservoirs with the largest amount of upward height growth there is still an enormous distance between the fracture and the aquifers.
There is, however, a host of laboratory, analytical, numerical-modeling, mineback, and field studies that have examined the issue of fracture height growth. Such growth is obviously undesirable since it wastes fluid, proppant, and horsepower. These studies have shown that in situ stress contrasts are the largest factor controlling fracture height, but other factors such as layering and high permeability layers are also controlling mechanisms and may severely curtail vertical fracture growth. For shallower reservoirs, the in situ stress state is not conducive to propagation of vertical fractures. The in situ vertical stress is generally found to be the smallest principal stress for reservoirs shallower than roughly 1500 ft and results in horizontal fractures that will not propagate upward. A compendium of surface-tiltmeter fracture-mapping results shows this behavior clearly, with mostly vertical fractures at depth and increasing horizontal components at shallower intervals.
All data from decades of investigation has shown that hydraulic fracturing in typical reservoirs is not a threat to fracture into and contaminate or otherwise disturb groundwater. These data show that fractures remained relatively confined within the reservoir and the nearby layers that serve to contain them.
Norm Warpinski is the Director of Technology for Pinnacle – A Halliburton Service in Houston, Texas, where he is in charge of developing new tools and analyses for hydraulic fracture mapping, reservoir monitoring, hydraulic fracture design and analysis, and integrated solutions for reservoir development. He joined Pinnacle in 2005 after previously working at Sandia National Laboratories from 1977 to 2005 on various projects in oil and gas, geothermal, carbon sequestration, waste repositories, and other geomechanics issues. Norm has extensive experience in various types of hydraulic fracture mapping and modeling and has been involved in large scale field experiments from both the hardware and software sides. He has also worked on formation evaluation, geomechanics, natural fractures, in situ stresses, rock behavior and rock testing. He received his MS and PhD in Mechanical Engineering from the University of Illinois, Champaign/Urbana in 1973 and 1977, respectively, after receiving a BS in Mechanical Engineering from Illinois Institute of Technology in 1971.