GAS SHALE- 1 Seven shale plays dominate today's North America natural gas potential reserves additions and production increases.

Production

Contrary to prior expectations of gas strat- egists and forecasts of gloom, ' today North America is awash in natural gas supply. While reduced demand (-1.6 bcfd) and the new Rockies Express pipeline (0.9 bcfd) have been partly responsible, gas shale development undoubtedly has been the single most important factor.

During the past 5 years, gas shale production grew to more than 8 bcfd from 2 bcfd (Fig. 1 ) . For some time now, shale and other unconventional reservoirs have helped stabilize US gas production, offsetting long-term production declines from conventional sources. Then, in recent years, the shale growth accelerated markedly, helping to push up overall US gas production into growth territory for the first time in a decade (Fig. 2).

The gas shale transition began with the Barnett shale in North Texas, fol- lowed by the Fayetteville in Arkansas and the Woodford in Oklahoma, and then was accelerated by the gas shales in the Haynesville and the Marcellus in the US and the Horn River and Montney in Canada (Fig. 3). Expectations are that these seven shale plays (the "Magnificent Seven") will dominate future natural gas reserves additions and production increases.

Building on the lessons learned from US and Canadian gas shales, various companies are starting to pursue overseas gas shale exploration in prospective areas such as Europe, Australia, India, and other countries.

From a resource once relegated to small independent producers, today majors, large independents and national companies are pursuing the play. How did this transition come about and where is it headed?

This three-part series on gas shale development begins with a look at the established and emerging North American shale basins and plays. The next two parts will examine the evolving technological and environmental considerations for optimally producing shale reservoirs as well as the potential for developing emerging gas shale plays in North America and elsewhere.

Shallow, deep shales

The Section 29 non conventional fuels tax credit in the 1980s helped develop and boost the economics of the marginally productive organic - rich gas shales such as Appalachia's Devonian Ohio shale and Michigan basin's Antrim shale.

Fig. 1

US UNCONVENTIONAL GAS PRODUCTION

Companies developed these shallow (500-2,500 ft deep) shale plays with conventional vertical wells and small hydraulic stimulations. Production was modest, generally about 1 00 Mcfd/well but long - lasting with reserves in the 0.25 bcf/well range. Fortunately, capital costs also were low.

Fig. 2

US GAS PRODUCTIVE CAPACITY

These shallow, low-maturity, clay- rich shale reservoirs store gas mainly from methane adsorption, with only a small porosity gas component. Today, these shallow shales produce about 1 bcfd.

Modern deep shale development began about 1995 with emergence of the Barnett shale play in the Fort Worth basin, North Texas (Fig. 4). Long known for its gas-rich deposit, the Barnett at 8,000 ft pushed the depth envelope for favorable flow capacity.

Mitchell Energy & Development Corp.'s innovative large slick- water fracs outperformed earlier small gel fracs but their vertical wells still recovered just a small percent of the gas in place.2 The first US Geological Survey assessment placed technical recovery from the Barnett Shale at just 3.4 tcf.3

Devon Energy Corp. acquired Mitchell in 2000 and recognized it could create more reservoir flow paths with a cased 4,000-ft horizontal well stimulated with large slick- water fracs containing several million pounds of sand proppant and pumped in 8- 1 2 stages. Recovery increased manyfold compared with earlier vertical wells. As horizontal drilling and fracturing technology advanced, Barnett core area wells have improved to an average 2.5 befe/ well. Current production from the entire play is almost 5 bcfed from more than 12,000 vertical and horizontal wells.

The Barnett 's core area sweet spot has favorable depth, thickness, thermal maturity, pressure gradient, and a hard underlying sandstone that acts as a hydraulic fracture stress barrier, focusing energy vvithin the shale reservoir. With access to new well performance and geologic data, an updated USGS resource assessment placed technical gas recovery from the Barnett at 26 tcf.4

At yearend 2008, however, cumulative production was 5 tcf with an additional 20 tcf of booked proved reserves, thus ultimate gas recovery needs an upward revision.

Fig. 3

MlD-2009 GAS SHALE PRODUCTION

Advanced Resources puts the remaining undeveloped recoverable resource from the Barnett at 1540 tcf, depending on gas prices. This gas play still has room to run.

Barnett lessons learned

A series of factors spurred the explosive growth of high-quality shale plays beyond the Barnett, as documented by internal studies performed recendy by Advanced Resources, to be discussed in the second article.

The factors include a greater geologic understanding, advances in drilling and completions, and access to land and infrastructure.

Although the Barnett shale was an acknowledged deep horizontal shale success, doubts lingered over whether it was merely a one-of- a-kind geologic setting, such as the still-unmatched San Juan fairway coalbed methane play in New Mexico. Not until 2006, following Southwestern Energy Co.'s Fayetteville and Newfield Enegy Co.'s Woodford shale production breakthroughs, were the doubters finally silenced and the new shale exploration and development paradigm confirmed.

As it turned out, shale plays do not have to be Barnett look- alikes; their geologic settings can be remarkably varied.

For instance, reservoir depth can range from 3,000 ft in the Fayetteville to more than 14,000 ft in the Haynesville.

The key geologic precursors for deep shales turned out to be different than for the shallow shale plays. Modest but adequate porosity (6-12%) is essential for gas storage. Unusual mineralogy, low in ductile clays and high in britde quartz, feldspar, and carbonate components, helps promote frac effectiveness.

The shale needs adequate thermal maturity (R^sub a^ >1.0%) to avoid unfavorable relative permeability from liquid hydrocarbons in the reservoir. Higher thermal maturity also promotes shrinkage of the total organic carbon (TOC) , leading to higher effective permeability and often a fully gas-charged system. The shale needs an adequate TOC (25%) for gas storage by adsorption.

An equally important factor, requiring 3D seismic, is the avoidance of geohazards, such as water-bearing karsts and faults.

Natural fracturing turned out to be somewhat less important than initially assumed. Even with permeabilities in the nanodarcy range, artificial stimulation could create the resevoir's flow capacity.

Horizontal drilling coupled with large slick- water hydraulic fracturing, employing ever-increasing lateral length and proppant loads, often guided by real-time seismic monitoring, provides much more effective (5-10 times) flow capacity than traditional vertical wells.

Today, deep shale drillers all employ essentially the same Barnett-style well drilling and completion design: +-4,000-ft long laterals stimulated by multimillion-lb slick- water fracs in a dozen stages. Armed with these new techniques, deep shale development is spreading rapidly to the Marcellus, Haynesville, and Horn River shales. Advancements continue, including simultaneous fracturing of closely spaced wells (600-800 ft apart) to contain the injected energy and more intensively shatter the shale reservoir.5

Fig. 4

B ARNETT GAS SHALE PLAY

Access, infrastructure

Companies generally can develop shale plays located in the US Midcontinent and East, where most land is owned privately, with minimal political wrangling.