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Hydraulic Fracturing Techbook 2018

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4 | August 2018 | hartenergy.com HYDRAULIC FRACTURING: INTRODUCTION also continued with high-strength proppants, cross- link fluids and foam fluids. This all pretty much ended between 1981 and 1986 with the collapse of the industry led by OPEC's increased production. Hydraulic fracturing and frac- turing technology entered a quiescent phase. One exception to this was in the area of fracture diagnos- tics with the early development of microseismic imag- ing and surface tiltmeter analysis. Major dividends from this, however, were not realized for another 15 years with their use in the unconventional reservoirs. After surges in the 1950s and 1970s, the third major surge of fracturing came about in the 2000s from the confluence of several events. These included the return of water fracturing, an increasing price for gas, importation of the water fracturing idea from the East Texas Cotton Valley tight gas play to the Barnett Shale in central Texas and the improvements in horizontal drilling. Working outward from one area of commer- cial production from the Barnett, Mitchell Energy explored it for many years, drilling vertical wells and performing massive fracture treatments using "conventional" ideas (i.e., viscous fluids). This was largely unsuccessful, with Mitchell at one point writing in a technical publication "natural frac- tures are detrimental to production in the Barnett Shale." This was undoubtedly due to gel plugging of natural fractures. If there was minimal natural fracturing, then the fracture treatment created a long fracture in a nano-D formation, yielding some production. In the presence of natural fractures, the resultant high fluid loss led to a very short hydrau- lic fracture, with gel then destroying any natural fracture permeability resulting in no production. This changed with the importation of the slickwa- ter fracturing idea from the East Texas Cotton Valley tight gas, leading to a boom in Barnett production beginning about 2002. It is noteworthy, however, that the initial adoption of slickwater fracturing was seen as a cost-reduction measure. Also, minimum proppant was used in what Mitchell Energy referred to as "light sand fractures." As Mitchell moved south from the "core area," high growth downward into the wet Ellenberger limestone became a serious impediment. This led to trials with horizontal wells. The use of horizontal wells was then expanded by Devon and, literally, the boom was on. Subsequently, with further increases in natural gas prices, the technology moved to other areas, principally the Eagle Ford in South Texas, and the Haynesville Shale in Louisiana. Barnett production then began to peak circa 2010, coinciding with a falling natural gas price, and this general trend was also seen in other shale gas areas. Simultaneously, an increasing trend in oil prices led to continuing activity in shale oil (e.g., Wolfcamp in the Permian Basin and Merrimack in central Oklahoma). Prop- pant mass use remained relatively small; in today's parlance proppant usage was on the order of a few hundred pounds per foot of lateral. This use of "minimal" proppant continued through many years of horizontal, multiple fractured shale wells. A full decade following the initial Barnett gas shale boom, proppant usage began to increase exponen- tially. Small fracture treatments with very little proppant eventually followed with much larger treatments with exponentially increasing proppant volumes, eventually leading to thousands of refracture candidate wells. The increased success with the larger treatments led to a continuing expansion of fracturing (despite recent setbacks). Again, the path forward focused on operational considerations and logistics–with the incredible industrial engineering achievements leading to efficiencies unthinkable even a short time ago. Treatment design then became a subject for trial and error, and statistical analysis through the use of Big Data. This brings us to the present, with more than 80% of activity concentrated in a few hotspot areas (Permian Basin, Marcellus Formation, Cana Woodford and Williston Basin) where current prac- tices allow profitable operations at $50/bbl. What next? If history is an indicator, it should once again be time to focus on the subsurface and the daunting geotechnical issues to be faced and solved. First among these is probably field/reservoir develop- ment with development drilling having to con- sider both lateral well placements and vertical well placements. Hopefully this can extend operations to other "not-so-hotspot" areas. n References available. About the author: Prior to joining Amoco Production Research, Mike Smith received a Ph.D. in mechanical engineering (rock mechanics) from Rice University. Amoco's main interest at the time was natural gas, with hydraulic fracturing research (tight gas, coalbed gas, shale gas, etc.) being critical. Subsequently Smith formed NSI Technologies (now part of Premier Oilfield Group), fracturing wells in more than 30 countries. Along the way he received the SPE Lester C. Uren Award for technical contributions prior to age 35, and, in 2018, was named by the SPE as a "Legend of Hydraulic Fracturing."

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