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Abstract

All Shale Gas reservoirs are not the same.  There are no typical Tight Gas reservoirs.  These two statements can be found numerous times in the literature on shale gas and tight gas reservoirs.  The one common aspect of developing these unconventional resources is that wells in both must be ‘hydraulically fractured’ in order to produce commercial amounts of gas.  Operator challenges and objectives to be accomplished during each phase of the Asset Life Cycle (Exploration, Appraisal, Development, Production, and Rejuvenation) of both shale gas and tight gas are similar.  Drilling, well design, completion methods and hydraulic fracturing are somewhat similar; but formation evaluation, reservoir analysis, and some of the production techniques are quite different.

Much of the experience in shale and tight gas has been developed in the US and in Canada, to a lesser extent; and most of the technologies that have been developed by operators and service companies are transferable to other parts of the world.  However, the infrastructure, including equipment and service company availability, governmental regulations, logistics, processing, environmental considerations, and pricing are not the same as in the US.  This may impact the rate of the technology transfer as well as the selection of some of the technology.  This paper is focused on operations challenges, technologies, and experience associated with shale and tight gas projects. It is likely that environmental concerns and the drive to reduce development costs of tight and shale gas reservoirs will drive new approaches to the development of these reservoirs in China, Latin America, Middle East, North Africa, and other parts of the world.

Introduction

Unconventional shale and tight gas development in the US was sparked by the 1980 introduction of The Alternative Fuel Production Credit of the Internal Revenue Code (an income tax credit).   “The 1980 WPT (windfall profit tax) included a $3.00 (in 1979 dollars) production tax credit to stimulate the supply of selected unconventional fuels: oil from shale or tar sands, gas produced from geo-pressurized brine, Devonian shale, tight formations, or coalbed methane, gas from biomass, and synthetic fuels from coal. In current dollars this credit, which is still in effect for certain types of fuels, was $6.56 per barrel of liquid fuels and about $1.16 per thousand cubic feet (mcf) of gas in 2004” (Lazzari 2006).  Initially, the credit was set to run until 1989; however, it was extended twice until the end of 1992 (Martin and Eid 2011).   

Higher gas price was another reason for the continued development of tight gas and especially shale gas.  Figure 1 shows Henry Hub spot prices from 2000 until January of 2012.  The “spot price” represents the price for natural gas sales contracted for next day or weekend delivery and transfer at a given trading location.  Henry Hub is the primary trading location, centralized point, for natural gas trading in the United States, and is often a representative measure for wellhead prices.  Higher prices are reflected by the six year (2003-2009) run of gas prices over $6 per MMBtu after generally hovering around $2 per MMBtu for the prior twenty-year period, 1980 to 2000.   During this time, two significant peaks in gas prices occurred.   In the summer of 2005, hurricanes along the U.S. Gulf Coast caused more than 800 billion cubic feet (Bcf) of natural gas production to be shut in between August 2005 and June 2006.  As a result of these disruptions, natural gas spot prices at times exceeded $15 per million Btu (MMBtu) in many spot market locations and fluctuated significantly over the subsequent months, reflecting the uncertainty over supplies (Mastrangelo 2007).  In 2008, due to physical and financial market factors, spot prices broke from the $6-$8 per MMBtu range of the two previous years and peaked at $13.32 per MMBtu, but ended the year at $5.63 per MMBtu.  This was the beginning of the current fall in gas prices.