US Shales: 6,000 Tcf from Sea to Shining Sea Building a boom on $3.75 gas

By Katie Mazerov, contributing editor

It’s being called everything from a game changer to the new gold rush. Armed with new technologies for tapping unconventional resources, energy companies are pushing the envelope to chase plentiful and increasingly recoverable natural gas in shale plays across much of North America and beyond.

An estimated 16,000 Tcf of shale gas-in-place exists worldwide, according to several studies, including one referenced by a 2007 National Petroleum Council study.

Nearly 6,000 Tcf of shale gas-in-place is thought to exist in North America; 3,526 Tcf in Central Asia and China; 2,547 Tcf in the Middle East and North Africa; and nearly 550 Tcf in Europe. The rest is located primarily in Asia Pacific.

“There is no question that shale gas has become a very significant player in the natural gas arena and one that is starting to sweep the world,” said Kent Perry, team leader for Research Partnership to Secure Energy for America (RPSEA), a research organization managing the largest ongoing  unconventional gas research program in the world.

“We conduct research to determine how much shale gas is available and where it is located, and then we chart a roadmap for tapping those resources by helping to develop technologies and disseminate them into the marketplace,” Mr Perry explained. “The goal of the research is to understand the shale gas that is technically recoverable and convert it into economically recoverable gas.”

New hydraulic fracturing and horizontal drilling technologies, along with systems for addressing water recycling and disposal, have ramped up shale production in the United States in recent years. Now, the industry is examining the potential for shale production in Europe.

But nowhere is the excitement about shale more evident right now than in the expansive Marcellus Shale play in the northeastern United States, and the newest of the plays, the Eagle Ford, in south central Texas.

Both, though still considered exploratory, are deemed to be good prospects for continued growth, believes John Keller, an analyst with Stephens Inc. “From an economic standpoint, we know that shale plays have changed the game for North American drilling and production, but we don’t yet know exactly how the game has changed,” he said, noting that the shale rig count is currently at an all-time high, exceeding 400 in the United States. “The Marcellus is arguably the best natural gas play from an economic perspective,” he continued. “The play’s proximity to big consuming regions leads to higher spot pricing, which helps drive higher returns.”

“A lot less is known about the Eagle Ford in terms of how that formation will shake out, but one aspect that will allow drilling to continue to move forward in the face of weak gas prices is the high liquid content of the play,” Mr Keller noted. “From an operator perspective, there are positives in deploying capital into a play where you are going to get at least some residual liquids production quickly, as opposed to pure, 100% dry gas.”

The Marcellus features around 489 Tcf of recoverable low-density, organic-rich shale a mile or more beneath the surface. It spans at least 30 million to 40 million acres across much of the Appalachian Mountains in Pennsylvania and West Virginia, parts of New York and Ohio, and small areas of Kentucky, Maryland, Tennessee and Virginia. Depths and difficult-to-access mountain areas and narrow roads, bridges and tunnels make the formation challenging for rigs and transportation.

The region’s proximity to several high-density urban markets and an existing pipeline infrastructure make it attractive economically but also pose some regulatory and environmental hurdles, especially for water disposal. Pennsylvania Gov. Edward Rendell has reportedly likened the state to the size of an OPEC country in terms of reserves.

“My view is that the Marcellus certainly looks like the real deal,” said Chris Strong, CEO, Union Drilling, which has 35 rigs operating in the play, 25 of which are smaller, older rigs that were working in the Appalachian Basin before the Marcellus potential was realized.

“We have drilled everywhere from the New Jersey border to eastern Ohio,” he said. “It seems to be one of the low-cost plays, where $3.75 gas is still economical, and that is very attractive to drilling contractors because we can get longer cycle times out of the rigs if we get into a situation like we’re in now, where commodity prices for gas are low.”

The number of large, interstate pipelines and good storage capacity in the Marcellus ensure operators can get their gas to market. “Rights of way and easements for existing, older pipelines are already in place, so if we need high-pressure trunk lines for higher quantities, the regulatory process is not as onerous,” Mr Strong said.

The potential in the Marcellus, which currently has between 60 and 70 rigs operating, to reach the 200-rig count where the Barnett Shale peaked, is “certainly possible,” Mr Strong believes, “but it is going to require some new equipment. We are about out of rigs in other areas of our fleet that we think make sense in the Marcellus market.”

Many newer rigs that were designed for other shale areas are not good candidates for the Marcellus play because the load sizes have to be much smaller, lighter and shorter for the terrain. “The larger loads that are suitable for the Barnett Shale, for example, are very difficult, if not impossible, to permit in Pennsylvania,” Mr Strong explained. “We need rigs large enough to handle the long (4,000-5,000 ft) horizontal drilling lengths, but able to be disassembled into small enough loads to efficiently move around in the Northeast.”

Mr Strong also sees a trend toward pad-drilling-capable rigs in the Marcellus. “If we can drill on larger pads, rather than having 10 locations with multiple roads and gathering systems, the drilling will be less invasive. Also, with the difficult winter in the Northeast, our customers experienced greater delays and loss of efficiency with rig moves than they have in other markets,” he continued. “With pad drilling, we can put a rig on a pad in the fall and not have to worry about moving it until spring.”

Mr Strong believes the industry will continue to build more electric rigs that require fewer, but larger, engines on location that burn less total fuel and have lower emissions. “There are no current requirements in our markets to file a carbon footprint for rigs engaged in oil and natural gas drilling, but lower fuel consumption and lower emissions are pluses for our customers and the environment,” he said.

While environmental issues are being addressed in Pennsylvania, the state is generally on board with natural gas activity because it means more jobs and a growing tax base, Mr Strong said.

Meanwhile, the state of New York is very concerned about environmental issues, with some expressing fears that wastewater produced after hydraulic fracturing may pollute the city’s water system.

“It is common knowledge that there are more regulatory hurdles east of the Appalachians where you have multi-state river basin authorities that have jurisdiction,” Mr Strong noted. “Some of those states are downstream of the Marcellus drilling and are not receiving any direct economic benefits from it. When there is little potential upside, it’s much easier to focus on the potential negatives.”

Water disposal is a universal issue in shale production due to the millions of gallons per well needed for hydraulic fracturing. But in the Marcellus play, the drilling water that contains salts and other contaminants is often trucked great distances for disposal. “In the Barnett, we were blessed with the porous Ellenburger formation, where water could be disposed of in wells 9,000 ft to 11,000 ft deep, beneath the natural gas-bearing formation and far below any freshwater aquifers,” Mr Strong said. “But the formations in Pennsylvania are not as porous or permeable, and wells can take far less water per day. So it becomes prohibitively expensive to dispose the water nearby as opposed to trucking it somewhere else, where it can be disposed of more readily.”

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Europe eyed as next shale nirvana, but regulatory, property rights hurdles loom

By Katie Mazerov, contributing editor

The shale bonanza in the United States has not gone unnoticed in other parts of the world. Efforts are under way in a number of areas, especially Europe, where an estimated 550 Tcf of shale gas is believed to exist, says Bojan Milkovic,  CEO and E&P executive director for INA Naftaplin, who will deliver the keynote address at the IADC World Drilling Conference, June 16-17 in Budapest. The reserves are found in the North Sea Graben, the West German basin, Poland, Ukraine, Romania and the Aquitaine Basin in southwestern France. Limited reserves are believed to exist in Albania, Turkey, Italy, the Adriatic region and Pannonian Basin in Central Europe.

“During the last two decades, the oil industry’s attention has been shifting more and more from conventional to unconventional gas resources,” Mr Milkovic said. “Natural gas is, with no doubt, considered to be one of the most environmentally friendly, cleanest, safest and most efficient sources of energy, and is already well accepted by end users.”

In Europe, the focus is on three main areas: Denmark-Sweden, France and Germany-Poland.

“We are still in the very early stages, but there is definitely much greater awareness of the shale potential,” said Florence Geny, a research fellow at the Oxford Institute for Energy Studies, which is conducting research on the potential of unconventional gas in Europe.

“Close to 50 companies have grabbed land in Europe,” she said. “The next stage will be about exploration and testing before we can move into a development and production cycle.” She said that Lane Energy, in partnership with ConocoPhillips, plans to drill three shale gas wells in Poland by June, and ExxonMobil has announced a drilling plan of 12 wells in Germany in 2010. “With these exploration wells, we are trying to determine if there is in fact gas in the shale and what the quality of the reservoirs are so we can determine the appropriate fracturing techniques,” Ms Geny explained.

Several companies, including ExxonMobil, Marathon Oil, Statoil, Schlumberger and others last year established GASH (World-leadinG innovAtive outStanding straigHtforward), a research initiative to study the potential of gas shales in Europe, particularly the Alum Shale in Denmark and the Posidonia and Carboniferous shales in Germany. The organization recently launched a six-year project to create a European black shale database.

While Europe’s long history of dependence on imported oil and gas has played a role in the heightened interest in shale, the real impetus has been the success of shale production in the United States that has resulted in an increase in reserves, a situation the Europeans have been closely monitoring.

“With the economic recession, spot prices for oil and gas have decreased along with demand,” Ms Geny explained. “But in Europe, gas is supplied under long-term agreements with a price that is oil-indexed. So even though spot prices decrease, long-term prices remain high, and most European utilities find themselves having to import very expensive gas when actually the spot market can supply cheaper gas.

“The real trigger was when Devon Energy cracked the code in the Barnett shale in 2005,” Ms Geny continued. “We’re looking at shale gas as providing security of supply, a way for Europe to try and decrease its dependence on imports and offset declines in commercial gas reserves.” Now, the Marcellus Shale has become the place Europeans are watching to gain greater understanding.

But Europeans face many hurdles in turning potential into reality, not the least of which is cost. “Shales in Europe are deeper, hotter, more pressurized, smaller and more compartmentalized,” Ms Geny said. “And that would increase drilling costs.”

Also, wages are higher in Europe and labor laws more protective and stringent. “And unlike the US, we don’t have a competitive service industry,” she pointed out. “So in the end, it’s a question of price and the relative cost competitiveness of shale gas.”

The land ownership structure is another concern. Unlike in the United States, landowners in Europe own only the surface land, not the mineral rights. “In Europe there really is no alignment between operator interests and private interests because individuals and local communities do not share in the gas profits, so they have no real incentive to support drilling,” Ms Geny said.

“Private owners would be compensated only for use of the land surface, and so they would likely be more concerned with quality of life, the landscape and quality of their drinking water,” she explained. “And before we see Europe really embracing shale gas, the United States would need to clear its own debate on environmental issues,” she noted. “We can import technology, but because Europe is so densely populated, we would need to develop more efficient operations to make the wells more productive.”

Mr Milkovic believes that in anticipating gas shale production in Europe, environmental regulations would likely become even more strict and demanding than they are now. “Host countries and local communities are not ready to let oil and gas companies explore and produce natural gas using unclean or, from an environmental point of view, unacceptable technology,” he said. “So today is the just the right time for the industry to start developing even more clean and environmentally friendly exploration and, equally important, production technologies.”

He cited 3D seismic testing, horizontal drilling and improved fracture stimulation as examples of technologies with significant impact in the last decade. “But in addition to these step-change technologies, continued improvements in core technical areas have been implemented as a result of the industry’s continuing efforts to search for more cost-effective ways to find, develop and operate unconventional gas reservoirs such as tight gas sand and gas shales. New designs in drilling bits, improved well planning and modern drilling rigs have also lowered drilling costs in many regions. Still, further improvements are expected in subsurface imaging  technologies, drilling, logging and completion equipment, as well as production technology.”

Range Resources, which has 13 rigs operating in southwestern Pennsylvania, last year introduced a water reuse technology that reuses all of the company’s water for Marcellus shale gas development in Pennsylvania, said Ray Walker, senior vice president of the company’s Marcellus Shale Division and chairman of the Marcellus Shale Coalition, an independent group that addresses such issues as water, the environment, education and outreach, regulatory issues, pipeline and infrastructure concerns, among others. The company expects to have 16 rigs operating in the Marcellus by the end of 2010 and 24 by the end of 2011.

“With this technology, we capture the water that flows to the surface after hydraulic fracturing, between 10% and 30%, and put it back into the impoundment. We also capture filtered drilling water and produced water in the impoundments. We then fill the impoundment with fresh water, diluting the salt water,” Mr Walker explained. “That water ends up being 70% to 90% fresh water, which we can then reuse.” By the end of 2009, the industry was recycling 60% of all Marcellus water using this technology.

Through the Marcellus Shale Coalition, the industry worked with the Pennsylvania Department of Environmental Protection to determine a set of regulations for moving the water around, storing it in the impoundments and constructing the impoundments. “There is a financial incentive to do this because it has actually saved us a lot of money – up to $200,000 per well – on two fronts,” Mr Walker said. “We don’t have to haul the water to a disposal facility, and we have to buy 10% to 30% less water. It also dramatically reduces local impacts from trucks and potential road damage that we are responsible for repairing.”

Range Resources was instrumental in forming the coalition in November 2009. The group has 30 producer members and 40 associate members and represents more than 96% of all Marcellus shale activity in the state of Pennsylvania, Mr Walker noted.

“We are very focused on doing things right, working with conservation groups, private citizens and regulators to make this work for everyone,” Mr Walker said. “I think all of us see the potential here, but we also see the importance of getting out and educating the public about what we’re doing and the state-of-the-art technology we use.”

Altela Inc, based in Albuquerque, NM, has developed what CEO Ned Godshall believes is a radical new solution for removing naturally occurring salts and other contaminants from water that flows back to the surface after fracturing and is produced along with the gas. The AltelaRain system, brought to market two years ago, has been utilized as a mobile unit in the Marcellus where, by continuously removing salts and contaminants, it converts water used for fracturing into water that is less than 50 mg/liter in salt concentration and ten times cleaner than drinking water.

The company’s first product, an 8 ft-by-45 ft portable unit, is deployed at the well site and uses low-grade heat or waste heat instead of electricity, and a non-pressurized technology whereby plastics, rather than corrodible metal, purify the water that can be reused. “If you’re not removing the salts, you’re not solving the problem,” Dr Godshall said, noting that the system is a “win-win” for both the environment and the energy industry because it allows operators to use recycled frac water, instead of fresh water, for subsequent fracturing jobs.

“We are the only economically viable water desalination and water remediation technology that does not use pressure,” he said. “As such, we don’t need pressure vessels, which must utilize expensive metals to reduce the inherent corrosion of pipes, valves, heat exchangers and reaction vessels when they come in contact with the brackish water. Our operating expense is much lower because we don’t need expensive electricity to run the large pumps required to create pressure.”

Altela is building its second product, a centralized, stationary plant in eastern Pennsylvania, to handle much larger volumes and that multiple companies can access. “We can make a water disposal treatment facility small enough in scale so we can have more facilities closer to wells, which reduces the cost of trucking,” Dr Godshall said, noting that the costs of water disposal can be very high in the Marcellus Shale because truckers have to drive great distances to transport the water back and forth.

While the Marcellus appears to be living up to its bounteous expectations, the industry’s eyes are also the Eagle Ford play, which spans from the Mexican border of south central Texas into Louisiana and is considered to be the source rock for the Austin Chalk that lies above it. Compared with other formations, it is brittle and contains high amounts of calcite and silica. The play’s boundaries have yet to be officially determined, but many in the industry believe it holds significant promise, both geographically and economically.

“The interesting feature about the Eagle Ford are the numerous phases in the formation,” said Mike Walen, chief operating officer and senior vice president, Cabot Oil & Gas Corp, which  completed its first well in March and plans to begin additional drilling this summer. “The northern part of the trend appears to be in an oil window where the wells are mostly oily,” he explained. “In the median area, we have a gas condensate window, and a dry gas window farther to the south.”

“We are seeing some great rates from the shale as far as oil production goes, but extracting the liquid out of the shale is more difficult because of the very small pore throat,” he said, noting that the rock is overpressured, which helps push the liquids out. “The economics of the Eagle Ford play have obviously been enhanced by the current price of oil,” he added.

Because the rock contains silica and carbonates, it fractures and props easily as sand does not become embedded in the fracture paths, Mr Walen noted. “The Eagle Ford really lends itself to a resource play because there is not a lot of variability in the rock and pressure regimes,” he said. “It’s all about the repeatability of the reservoir and the execution by the operator to get the hydrocarbons out and thereby, over time, drive down costs.”

Petrohawk Energy Corp has seven rigs in the Eagle Ford and plans to drill several more exploratory wells by the end of the year, said James Redfearn, vice president of drilling and completions. He said Petrohawk’s position in the play, which, unlike the Marcellus, features larger tracts of land without proximity to urban areas, holds an estimated 11 Tcf of resource potential, equating to about 5,600 drilling sites. Petrohawk’s initial acreage was 165,000 net acres, a figure that has more than doubled to 360,000 net acres in the past year.

“Comparatively, the Eagle Ford has a very thick reservoir, maybe 250-ft thick, with a lot of gas per square mile,” Mr Redfearn said. “The thickness dictates that we develop a stimulation program where we contact all of that rock, from the base to the top,” he explained. “The areas with a fairly high condensate yield fit well with today’s pricing, but you have to consider that the relative permeability of the liquids is going to be less than that to gas.”

“The rock may be easier to break down and fracture due to its brittleness and the elements,” he continued, “but at the end of the day, we need a design treatment that will maximize recovery and prop the rock open so the condensate will flow out along with the gas.”

Drilling and completion rigs are fairly well equipped to handle the design of the wells today, but Mr Refearn anticipates techniques will evolve. “Drilling longer laterals, pad drilling and other optimization techniques going forward will require innovation,” he said.

Houston-based Global Energy Services, which designs drilling systems and rig components, recently unveiled its new Ultra rig, featuring a hydraulic rig-walking design that was developed for shale drilling. “With shale, the loads are smaller, and operators typically have to drill multiple wells,” said COO Mike Stansberry.  “With the Ultra, operators can move from well to well without having to rig down. It also leaves a smaller footprint.”

In designing the rig, GES took components from its two existing classes of rigs: the Pioneer, a pad-drilling rig that skids on an X and Y axis, and the QuickSilver, which Mr Stansberry believes is the “quickest-moving rig on the market today.”

“We tweaked existing technology, combined the best features of both and talked to about a dozen drilling contractors,” Mr Stansberry said. The end result was the Ultra. It is designed with four “walking shoes,” one shoe in each corner of a parallelogram, that can pick the rig up, take steps and then set it down. The unit can move up to 40 ft/hour. The rig can be operational in six to eight months, according to the company.

“The Ultra is a four-axis walking system that can move north, south, east and west and at 45° angles,” Mr Stansberry explained. It features a hydraulic power unit placed on the drill floor along with electronic drives that run the engine. “This is important because as you go ‘walking,’ you are carrying all your power sources with you instead of leaving them behind,” Mr Stansberry said.

A mud boom transfers mud from the wellbore back into the mud system.  “We’ve adapted the boom for our rig so that when mud comes out of the wellbore, we have a mud boom that reaches up to 120 ft away so we don’t have to keep moving hoses and modifying,” Mr Stansberry explained.

Safety, mobility, efficiency and economy were the driving forces behind the design. “This rig assembles at ground level, so nobody has to get up in the air,” he said. “It does not require a crane, can move in 26 loads and can rig down, move 100 miles and rig up in 48 hours. That is 10 to 15 loads less than a conventional drilling rig,” he added. “So the cost saving is great.”

While technology continues to advance shale production, the underlying issue that everyone is watching is gas prices, which remain low, especially as the industry moves from withdrawal season into the injection season.

“Whether we have too much supply today doesn’t really matter,” analyst John Keller believes. “But the assumption is that we are going to have way too much supply tomorrow, given the recent acceleration of the rig count coupled with production that never really came down when rigs stopped working in 2009. Based on that, I would say the pricing outlook for the next four to six months is pretty bleak.”

What could impact supply is heightened regulation. “The industry doesn’t seem to have any problems operating the current regulatory environment,” Mr Keller said. “But if new regulations were to significantly drive up the cost of fracturing wells, that could be a game changer in how we develop natural gas in this country. And we could see natural gas prices move materially higher as production wanes and supply is reduced.”

A video interview with Global Energy Services COO Mike Stansberry can be viewed below.

A video demonstration of Altela water desalination system can be viewed below.