After a long period of relative predictability, the U.S. natural gas market threw some curves in the past few years. Domestic production continues to grow, despite the drop in drilling activity in 2009, and it is now commonly understood that innovations in recovery technology are driving production growth. Now more than ever, E&P management teams need to understand the impact of these innovations and their implications.

The Production Puzzle

The accepted wisdom in the E&P industry from the late 1990s through the mid-2000s was that declining well productivity would eventually result in a domestic-production plateau. Until January 2006 the rig count had increased more or less steadily for a decade, and U.S. production had remained flat. But these expectations were turned on their head from 2006 to 2009, when domestic production grew 15%, filling storage to near capacity. Not until this past winter—the coldest in decades, according to the University Corporation for Atmospheric Research—did storage drawdowns occur.

When the gas rig count started to drop in September 2008, the persistence of relatively high domestic gas production seemed counterintuitive. From peak to trough, 57% of domestic rigs drilling for gas became inactive or were retired. Additionally, it was widely expected that most of the new wells, which were unconventional, would produce on a steep decline curve, and that the drop in drilling activity would quickly bring the market back into balance, or even a shortage, with prices revisiting $8 per million British thermal units (MMBtu) or higher.

Reflecting this optimism, the futures market persistently priced contracts for late 2010 at around $7 per MMBtu for one full year after the initial drop in rig activity. But production did not drop, and supply has continued to outstrip demand. The spot market has since dropped to around $4 per MMBtu, and the futures curve has flattened.

This sustained increase in production has significantly disrupted the liquefied natural gas (LNG) market in North America. Before last year, the anticipated gap between domestic production and growing demand was presumed to be met by LNG. Many companies invested millions of dollars to plan and seek permits for regasification plants.

By early 2006, some 60 regasification plants had been proposed for North America, greatly expanding capacity beyond the four plants then in service. In the three years since, those companies have either shelved or publicly abandoned those projects. Today, the number of proposed regasification plants has dropped to seven, according to the Federal Energy Regulatory Commission’s Office of Energy Projects.

Clearly, the status quo has changed. Just as the futures and LNG markets have adjusted to the new and persistent growth of domestic supply, companies’ strategies must also adapt.

Wonders We Have Seen

On one level, major technological innovations in the natural gas industry are not new. Horizontal drilling is at least three decades old, and hydraulic fracturing is even older. Likewise, the combination of these two, with improved zonal control of the frac, has been tested for years. At the simplest level, all that is accomplished with this combination is greater total surface contact with the reservoir. On its own, this might not be a game-changer.

The greater impact of this technology has come from refinement of the design for local circumstances and widespread adoption across the continent. Zonal control has improved through several generations of design. Next-generation steerable systems have enhanced wellbore placement. And the impact of a single wellbore has increased as lateral sections have extended from a few hundred feet to several thousand feet. The optimal combination of these advances has been refined, often through informed trial and error, in thousands of fields. So, it is difficult to appreciate the potential impact of this technology package without also considering the journey towards its adoption.

Viewed this way, the shift in drilling activity in 2008 was driven more by a change-out from old to new technology than by a drop in activity. Horizontal and directional rigs already had been making inroads in the U.S., especially after 2005. The economic crisis of 2008 simply accelerated a process that was well under way. The relative economic advantage of horizontal technology led to its increased market share, especially as lower gas prices motivated producers to switch to the more efficient technology.

An equally instructive market trend is the growth in tight-sands production. In spite of the recent interest in shale gas, the greater contributor to growing U.S. gas production to date has been tight sands.

Viewed over the past two decades, this is instructive for two reasons. First, the industry’s ability to develop tight, thin sands has increased steadily during that time frame, with some acceleration in the past five years. So the time required to develop this previously non-commercial resource on a continental scale has been measured in decades, and tight-sand gas production is still increasing.

Furthermore, tight-sands gas production was increasing before widespread adoption of horizontal drilling with zonally controlled fracturing. Other technologies, from 3-D seismic to thin-bed resolution logging tools, helped develop tight-sands reservoirs more economically. The latest round of drilling and completion technology simply accelerated the trend.

Today, shale gas appears to be in a position similar to tight sands 20 years ago. The recent initial round of technology improvements has unlocked some of the resources. Subsequent rounds of technological improvement, and widespread adoption, could have a similar (or greater) effect on shale-gas production and thus on total U.S. production. Horizontal and directional drilling, along with hydraulic fracturing, could also significantly impact coalbed-methane production, but dewatering costs and modeling reservoir characterization remain significant challenges.

Impressive IPs

Even with only a few years of production data to date, the results from extended lateral horizontal-drilling technology, coupled with zonally controlled multistage fracturing, have grabbed mainstream attention. One way to measure this impact is by initial production (defined as the first three months of production) per well, and some of the results being posted strain belief.

Normally, as a basin is developed, its initial well productivity declines, with the best areas developed first and more marginal areas later. Instead, basins are posting increases in initial productivity, including in the relatively mature conventional tight sands of East Texas. The industry has been able to produce more and more as technology is applied more extensively.

There is a natural limit to how far the technology can be pushed (i.e. the industry has gone from two frac jobs per well to 20, but will never reach 200), but we have not yet exhausted its potential. As exemplified by the Fayetteville shale, new plays being developed are expected to economically produce at a much higher level than what was possible just five years ago. This is exceptional and reinforces the idea that shale-gas production will continue to grow for a long time and defy conventional wisdom.

The potential scale and impact of these innovations creates a communication and even a cognitive challenge for E&P management teams. The challenge is to explain to other industries and governments the magnitude of these innovations. Step-level technological innovation from the E&P industry isn’t expected, because it is perceived as a stable “low-tech” industry with only incremental improvements.

It is quite likely the E&P industry now has the ability to produce domestically 15% to 30% more gas at current $4/MMBtu prices. Just as with LNG regasification plants, the expanded domestic supply base can/should alter long-term investment decisions for North American industries. E&P management teams will be challenged to explain the new market dynamics to both insiders and outsiders as companies seek opportunities.

A Classic Discontinuity

At its core, the U.S. gas market is experiencing a technological discontinuity similar to those in other industries. It fits the pattern of a competence-enhancing, process-based discontinuity, according to parameters identified in an article in “Administrative Science Quarterly” by P. Anderson and Michael Tushman. There are well-documented instances of similar innovations, in industries as diverse as earth moving, glass making and minicomputers.

For example, from 1904 to 1916, automated bottle-making machines expanded productivity of glass bottle making 15 times, over a series of five related innovations. The contemporary analogy with multistage fracs immediately comes to mind. This earlier discontinuity changed not just how bottles were made, but who made glass bottles, how many glass bottles were needed and how they were used. The same questions apply in the case of natural gas production.

The pattern of behavior from this kind of technological discontinuity is fairly well established. Since it is competence-enhancing, we expect the main beneficiaries to be companies already in the business. We expect an “era of ferment” after the introduction of the new technology, where trial and error leads to a “dominant design” that most efficiently incorporates the technology. Clearly, we have witnessed that phenomenon in natural gas production over the past few years.

We also expect to see more incremental, evolutionary change after the basic introduction, adding to the impact of discontinuity. For the contemporary drilling and completion technology package, the steady increase in length of horizontal sections and number of stages in a frac fit this model.

Finally, we expect that the innovation does not become mainstream, and its full potential is not felt, until it captures around 50% of its market. Directional and horizontal drilling captured 50% market share in September 2008, and the term “shale gale” is now de rigueur. So it is reasonable to add gas drilling and completion to industries where technological discontinuities fundamentally changed the landscape.

Implications

Technological innovation of this magnitude affects companies on two levels. First, it affects the macro-level supply-demand balance for gas, with consequent impact on pricing. While influential, gas pricing is a function of many factors: LNG imports, overall economic growth, and legislative changes that impact structural demand. Focusing too much on the discontinuity’s pricing implications can distract from the more important second level—what actions individual firms can take today.

With that in mind, management teams can take these steps:

Accept that we do not yet understand the full impact of the current discontinuity, and plan accordingly. The industry developed an understanding of the link between activity level and output based on the previous generation of drilling and completion technology. Today’s technological discontinuity nullifies that understanding. We are in the maturing phase of the “ferment” period; a period in which other industries saw significant waste as resources were misapplied. Further innovations are likely to be evolutionary until the next big wave of innovation arrives (see below).

In the meantime, the industry will update its understanding of the link between activity level and production, leading to a more stable activity level over time. Until that stability is reached, companies should review plans and commitments, and they should modify capital and expense-planning processes to operate on a shorter cycle, especially since this discontinuity involves increased well productivity.

Experiment with and optimize the new technology in operations. As opposed to a single breakthrough, this technological discontinuity is based on a bundle of innovations that have to be customized to local conditions. As such, companies will compete locally to get the mix right, which in the medium term will help determine whether the economics of purchased/leased assets pay out.

Getting the mix right relies on a combination of observation and structured experimentation. The observation part includes scouting how others nearby are drilling and completing wells, and it also includes drawing longer distance analogies based on comparability of reservoir rocks and fluids. This will help with initial well designs, which will then have to be optimized via structured experimentation as development proceeds.

Depending on the circumstances, it may be best for companies to try multiple designs in parallel and then choose a best path, or to move sequentially in a very patient manner. Factors in this trade-off include the size of the asset, its profitability, the quality of scouting and analogies, pipeline and infrastructure constraints, and the internal technical capabilities of the operator. Over time, each area will evolve toward a best practice, a “dominant design.” It is important for companies to not fall behind in the search for the best mix of applied technologies, yet each company will take different paths.

Survey the boundaries of noncommercial assets. An impact of this technological discontinuity is that many previously nonproductive or marginally commercial assets will become valuable. In natural resources businesses like E&P and mining, there is a gradual conversion of assets into economically viable assets as deeper reservoirs, offshore resources and poorer quality rocks progressively become more accessible. The distribution in quality of these resources tends to be exponential, with only a small amount of high-quality reservoirs, a much larger amount of medium-quality reservoirs, and a very large amount of marginal reservoirs.

The latest set of innovations, especially with shale gas, changes the economics and invites the potential development of a very large pool of resources. Companies should review their actual and potential holdings to see which resources may move across the line from uninteresting to potentially valuable.

Be on guard for signs of the next technological discontinuity in gas production. The productivity improvement being delivered by the current technological discontinuity has turned the LNG industry on its head, and has implications for long-term supply for North America and the rest of the world. Even so, there are limitations in current gas-development practices, most notably in reservoir characterization.

The current development pattern in resource plays involves a lot of trial and error, thanks to a lack of inexpensive reliable characterization technology and high levels of reservoir anisotropy. The next major innovation could come in drilling and completion, like the recent one—a good example being expansion of real-time fracture monitoring. But equally, it could come in reservoir characterization which, coupled with the current technology, could greatly reduce the unit cost of developing these plays.

For example, early-stage wellbore seismic technologies have the potential to improve well position and productivity. Companies should closely monitor the development of these technologies, especially beyond drilling and completions, because they could have a dramatic impact on unit cost of production.

Watch out for outsiders. The current discontinuity is competence-enhancing in that it builds on earlier generations of drilling and completion technology. The benefits from this kind of innovation tend to flow to existing players. Nevertheless, outside companies with ambitions to take advantage of this technological discontinuity will and, in some cases, already are entering the market.
These entering companies may simply be oil-centric companies wanting to more heavily diversify into gas, especially after the Deepwater Horizon fall-out. For existing players, this presents both a partnering opportunity and a threat of market disruption. Companies need to factor in the impact of these potentially large new entrants.

Promote new uses for natural gas. At one level this is an industry issue, rather than a company issue. But companies participate in industry groups, and individuals will have to take the lead either directly or indirectly.

Current technology innovations have effectively multiplied the domestic gas-resource base by a growing (and not yet final) factor, best practices are still evolving, and companies have not yet had the time to apply new technology to all existing resources. Even with the current multiplication factor, the U.S. gas base can support greater uses than just being a fuel source for peak electrical power, some residential and commercial heating and declining industrial applications. Increased use for baseload power generation and direct use as a transportation fuel are obvious opportunities.

For example, if a company believes abundant gas will mean that gas power plants will become more economic than coal, then why not own some of those assets and change the way they operate? Or, many oil companies own or have access to large branded retail-transportation-fuel outlets. Why not strike a deal with auto manufacturers, who have already developed the technology to make switchable vehicles in other markets, such as Brazil?

It seems the E&P industry has discovered something about resource availability that related industries do not yet fully comprehend. What would abundant gas across North America at $5 per MMBtu until at least 2050 mean for industries like chemicals, electric power generation, and transportation?

Rethinking Value

Given these new market conditions, it is reasonable to believe that, absent crippling regulations and excluding leasing costs, the U.S. can maintain gas production levels at current real costs for several decades to come. Communicating this new reality to related industries and other stakeholders will revolutionize how North American natural gas is viewed and used, and will define winners and losers.

Al Escher leads and Kathryn Hite is a consultant with Schlumberger Business Consulting in North and South America.