US market going strong; in emerging markets, potential being weighed against challenges Conventional wisdom has its place, but when it comes to land drilling, the thinking these days has a definite unconventional spin. “Unconventional” includes the vast shale plays that continue to be developed and discovered, not just in North America but also in basins worldwide. Although the US currently leads the globe in shale oil and gas production, industry is eyeing opportunities in other markets as well, such as China and Australia. In Latin America, too, prospects are heating up and a shale gas factory-drilling program is set to launch this year in Argentina. Companies also are considering shale gas production in Europe, with the goal of establishing energy independence in countries such as Poland and the UK. Russia, while it is still a strong conventional market, also boasts significant potential unconventional resources.
Although the resource potential is high, so are challenges in their development. Lack of infrastructure, equipment and technology, economics, political and cultural barriers and regulation all pose difficulties, particularly outside the US. In its efforts to launch a drilling exploration campaign in the Bowland Shale, a rich shale gas basin in northwest UK, Cuadrilla Resources recently postponed drilling for a second time due to environmental concerns. Unlike the US, mineral rights in other countries are owned by the government, not individual landowners.
There is also a growing trend of nationalism when it comes to unconventionals development, particularly in energy-thirsty India and China, where NOCs are trying to import the technologies and expertise that have propelled US production, said Matthew Jurecky, global director of energy research and consulting for GlobalData. “China, for example, is essentially a closed market, with state-owned operators developing vertical companies that include drilling and service components so they no longer need Western companies.”
Meanwhile, US land drilling is still recovering from a slight downturn in activity in 2012. US operators now are looking forward to ramp-ups in their drilling programs again, while contractors are seeing dayrates stabilize and rig utilization tick upward.
Despite continued flat natural gas prices in the US, the long-term outlook for shale gas is healthy. A comprehensive University of Texas (UT) study puts total recoverable reserves in the Barnett Shale at 44 trillion cubic ft (Tcf), more than three times the cumulative production of 13 Tcf to date, with production slowly declining through 2030. UT plans to release findings from the Fayetteville, Haynesville and Marcellus plays later this year.
Encana has set its 2013 upstream capital investment to range between US $2.9 billion to $3.1 billion, with approximately 80% for unconventional light oil and liquids-rich natural gas plays. These include the Bighorn and Jonah natural gas plays in Wyoming; the Piceance Basin and Niobrara (Denver-Julesburg Basin) in Colorado; Cutbank Ridge, a tight-gas play in British Columbia and Peace River Arch in Alberta, according to company spokesman Doug McIntyre.
The remainder of that 80% will be invested in emerging shale plays such as the Duvernay, believed to hold huge reserves of oil and gas, in Alberta; the Tuscaloosa Marine oil and gas shale in Louisiana and Mississippi; and the San Juan Basin in southwestern Colorado/northeastern New Mexico. The company plans to spend the balance of its operating capital, approximately 20%, in dry natural gas assets.
“We’re encouraged by results in a number of our emerging plays, and we are proceeding with a measured pace of development in those areas,” Mr McIntyre said. The company’s total rig count in the US and Canada averaged 38 in 2012, a number that is expected to increase slightly in 2013.
“This winter has been 7% warmer than the 10-year average but 6% colder than last year,” he continued. “This has put downward pressure on prices as the market seeks a price level that will induce sufficient price-sensitive demand from coal-to-gas displacement in power-generation to balance the market. In 2012, there was an increase in coal-to-gas displacement driven by lower natural gas prices. We expect a certain level of coal-to-gas displacement will still be required in 2013, but the amount will depend on weather-sensitive demand and the year-over-year change in production.”
Patterson-UTI Drilling, which is operating approximately 200 of its fleet of more than 300 rigs in plays throughout the US and up to the Arctic Circle of Canada’s Yukon Territory, also expects a strong year. The company’s high-spec APEX rig series, designed for unconventional pad drilling, is seeing utilization rates of more than 90%. “Everything is shifting to the unconventionals where possible and where operators can get a good return on their investment,” said Patterson-UTI Energy CEO Andy Hendricks. Dayrates have generally been “holding steady” across all classes of rigs, including the older mechanical rigs due to their various upgrades.
“In early 2012, the US land rig count was at a peak, but a fall in commodity prices, with per-barrel oil prices dropping to the mid-$80s, precipitated about a 15% drop in the rig count,” he noted. “With the recovery in prices, operator spending is projected to be flat year-on-year, and we’re already seeing the rig count inch back up. Our rig count at the end of 2013 may not be back to the peak of early 2012, but the market will move toward that level, which is up from where we are today, by the end of 2013.”
Patterson-UTI, one of the three biggest US land drillers, plans on building 13 new rigs this year, including one APEX WALKING rig and 12 fast-moving APEX-XK rigs, most of which will be outfitted with a walking system. “The new-generation APEX-XK 1000 and APEX-XK 1,500-hp rigs are designed with more clearance in the substructure to accommodate a walking system,” Mr Hendricks explained.
The APEX rigs account for about half of Patterson-UTI’s working fleet, all drilling horizontal wells in unconventional plays. The APEX WALKING rig is currently designed with AC technology for large pads with six or more wells where the rig does not need to move frequently. The remainder of the fleet are a mix of mechanical and SCR electrical rigs, which have been upgraded with features
such as AC top drives and hydraulic catwalks and are drilling horizontal wells in unconventional plays, including the Bakken. “All our rigs, including mechanicals, have some form of automation or mechanization,” Mr Hendricks said.
The company also continues to have a strong presence in the Permian Basin, characterized by stacked plays, that is transitioning from vertical to horizontal wells as some operators are realizing wells can be drilled in more than one layer, he said. The company has approximately 30 rigs operating across the Rockies and about 20 rigs in the Marcellus, where gas prices are more favorable because of its proximity to consumer markets.
Drilling is also ongoing in northern Oklahoma’s Mississippi Lime play, whose carbonate features and relatively shallow shale layers make for somewhat easier drilling. “Production there hasn’t been at the level originally projected, so operators are a bit more cautious now,” Mr Hendricks said. The same is true for the Utica, where operators are still studying reservoir geology and dealing with product takeaway issues in Ohio.
Production in the Eagle Ford has remained stable, while activity in the Bakken saw a slowdown in 2012 in response to lower oil prices. “The Bakken has the highest operating costs in the US, and when oil prices drop, the Bakken is the first to slow down due to the higher costs of running a rig, winterization and issues around housing,” Mr Hendricks said.
On the personnel side, Patterson-UTI launched a recruiting drive last year; the goal is to fill 40% of new-hire spots with returning military personnel. The program was ranked 16th out of the top 100 Military-Friendly Employers by GI Jobs, a business that serves the military community, and the company was named one of the Most Valuable Employers for Military by CivilianJobs.com.
Walking, dual-fuel rigs
Independence Contract Drilling recently introduced its 200 ShaleDriller rig series, a 1,500-hp design for multi-well pad drilling that features a built-in walking system and a dual-fuel component that allows the rig to operate on both diesel and natural gas. The company has four rigs operating in unconventional plays – two in the Woodford Shale in Oklahoma, one in the Permian Basin working for Apache Corp and one in the Eagle Ford working for Newfield Exploration, said Chris Menefee, vice president and general manager.
“This rig design is targeting shale plays where operators want to spend their time and money drilling, not moving rigs,” he said. “I don’t foresee any huge swings in market activity in the near term, but our customers are interested in upgrading their fleets by replacing older, average-performing rigs for new, more efficient designs.” Independence has two more of the ShaleDriller rigs coming out this year – one in early May and the other in late June. The company anticipates further growing its fleet for work on multi-well pads.
The ShaleDriller rig is designed with four integrated walking shoes driven by hydraulic cylinders, one on each corner of the substructure, that allow the rig to move up to 60 ft/hr. The entire substructure is hydraulically risen with cylinders in one load, versus the conventional two to four loads, Mr Menefee explained. The rig floor itself is raised and expanded with wings and hydraulic driving pins, all driven remotely. The rig also is designed to move from well to well with a full complement of drill pipe in the mast and does not require a crane for conventional rig moves.
“By adding in the dual-fuel capability, we are delivering a rig that the big players in the land business want,” Mr Menefee said. The engine package on the rig is outfitted with a train and skids that can be changed to filter certain types of gas – liquefied natural gas or dry gas – to the rig, allowing it to run on a blend of gas and diesel. The dual-fuel system has been contracted by a major operator in the Permian Basin, where the open spaces are particularly suited to building an infrastructure for transporting gas to the well site.
Mr Menefee said he believes that new rig designs coming into the marketplace mean it’s more important than ever that industry renews training efforts, providing crews with the skills required to operate the hydraulics.
“People are key to the success of any operation. An experienced rig crew that has worked together will drill circles around a rig with inexperienced people who have never worked together. A lot of companies have thrown millions of dollars at new rigs but don’t have trained people to operate them. A balanced approach with the right iron, the right technology, automation, a well-trained crew and focus on safety is what will drive success.”
Factory drilling in Argentina
While the US, with a sophisticated infrastructure and easy access to state-of-the-art technology, remains the top shale market, Latin America is moving up in the unconventional world, now ranking fourth behind the US, China and Russia in terms of reserve estimates, said Victor Villegas, regional director, Latin America operators, for Nabors.
“Based on the technology available today, there is more than 1,900 Tcf of technically recoverable shale gas in Latin America,” Mr Villegas said. Argentina, with an estimated 774 Tcf of recoverable shale gas, and Mexico are the region’s top two markets; more moderate reserves are located in Colombia, Brazil, Bolivia, Chile, Uruguay and Paraguay. Venezuela has the largest unconventional heavy oil reserves in the world.
Nabors has operated in Argentina for more than 20 years, with 20 rigs drilling for both conventional and unconventional resources. These include five drilling rigs and five workover rigs in the country’s long-producing Vaca Muerta field in the massive Neuquén Basin, where state-owned Yacimientos Petroliferos Fiscales (YPF) will this year launch a factory-drilling pilot program, including 48 horizontal wells and 84 vertical wells, in hopes of getting an extensive shale gas project up and running.
Spanning 30,000 sq km, the Vaca Muerta field alone is estimated to hold 660 billion bbls of oil in place and 1,181 Tcf of oil-gas in place, Mr Villegas said. “Factory drilling is the only way unconventional production can be economically viable in this complex field, where the shale ranges from 30 to 450 meters in thickness (compared with 10 to 80 meters in the Eagle Ford) and reservoirs are highly pressurized.”
The Neuquén Basin has other oil and gas shale plays and tight-gas fields that have attracted several IOCs, including ExxonMobil, Chevron and Chesapeake, he noted. Other regions of the country also hold unconventional resources.
“The service companies and IOCs that YPF is partnering with can provide the technology, but there are challenges in terms of the infrastructure needed to supply water and transport equipment efficiently,” Mr Villegas said. YPF has built a 400-sq-km (154-sq-miles) reservoir in the Neuquén Basin to provide water for hydraulic fracturing, but transportation remains an issue. The country’s strong trucking union has stymied development of a rail system, which means that the only way to move sand, water and fracturing equipment is by truck, which is less efficient and frequently impacted by drivers going on strike.
Nabors plans to ultimately replace or upgrade the 10 older, box-on-box style rigs currently drilling single wells in the Vaca Muerta with fast-moving rigs that can skid once pad drilling gets under way. “Argentina has been a soft drilling market in terms of low dayrates and high operating costs, so we haven’t seen an influx of new technology,” Mr Villegas said. “But for this shale play, (YPF) will have to bring in advanced, high-tech rigs, meaning dayrates will increase from low to moderate.” The more advanced rigs also will require a significant investment in local training efforts.
With 681 Tcf of technically recoverable shale gas resources, Mexico is close behind Argentina, with the most significant play an extension of the Eagle Ford in northern Mexico, which also has liquids in place. However, prospects for production in the foreseeable future are uncertain because state-owned PEMEX has yet to make a significant investment in the field, and the country’s constitution currently doesn’t allow PEMEX to enter into any production-sharing agreements with IOCs, Mr Villegas said.
In Venezuela, Nabors has been active for nearly 50 years and has five rigs operating in the Faja field in the Orinoco Province. It is currently supplying skiddable rigs for a pad drilling operation by a joint venture (JV) of Chevron and NOC Petroleos de Venezuela (PDVSA). “The political regime (under the late Hugo Chavez) has made Venezuela a difficult place to work,” Mr Villegas acknowledged. “All IOCs must operate under a JV with PDVSA, which wants to vertically integrate into the services side of the business rather than depend on Western drilling contractors. Two years ago, the company purchased 100 rigs from China but lacks the infrastructure to keep them operating efficiently.”
Uncertainty in Europe
On the European front, a report from GlobalData cites estimates from the International Energy Agency (IEA) that puts unconventional gas reserves in Europe, including tight gas, shale gas and coalbed methane, at 3,500 Tcf. Poland has been considered the most promising market for shale gas development, but more than 1,200 Tcf of shale gas reserves are estimated to exist in a field in the UK’s northwest region.
Uncertainty remains over the technical recoverability of European reserves, however, along with regulatory, environmental and political challenges and equipment shortages, according to GlobalData’s Matthew Jurecky. “North America, with reserves that span areas of low population density, dwarfs less commercially viable opportunities in Europe,” he said. “For that reason, service equipment for shale gas production is not as available in Europe.”
Poland, whose technically recoverable shale gas reserves were estimated at 187 Tcf in a 2011 IEA study, has seen some setbacks in its unconventionals market. ExxonMobil, for example, pulled out last year after disappointing results from appraisal wells.
Further, the market for Polish shale gas is more limited. “State-owned PGNiG wants to partner with the IOCs that have the expertise and technology, but it can only sell to the Polish market,” Mr Jurecky explained. “The objective for the European NOCs is not to be profitable but to produce energy to fuel these countries looking to sever their dependence on Russia. By contrast, North America, with the huge gas market for potential export along with a growing domestic market for natural gas, is a more attractive investment opportunity for major operators.”
The Polish government has proposed relaxing environmental regulations and adjusting fiscal policies to make shale gas production more financially attractive, Mr Jurecky said. However, the Polish Clean Energy Foundation has submitted its own report questioning those measures and offering guidelines for environmental considerations regarding future development. Meanwhile, Germany, which is shifting away from nuclear power, is debating hydraulic fracturing, he added.
Mr Jurecky believes US investors should have strong motivation to encourage and sponsor shale gas development in European countries, citing “the economic impact and commercial viability of oil and gas production in terms of jobs creation, growth for local economies and an improved trade balance for the US.”
KCA DEUTAG has a rig working for an independent operator in Poland’s Orzechow shale gas play, which spans the country. The T-207 is a skiddable 1,500-hp rig with an automatic drawworks control system and automatic driller system, with capacity to drill to 18,000 ft.
“Two years ago, there was a lot of excitement and opportunity in Poland and not enough rigs to meet the demand,” said Rodrigo Rendon, KCA DEUTAG head of business development. “Today, the view is not so optimistic. Drilling contractors are struggling to secure long-term contracts and starting to move rigs out of the country, looking for longer-term and more secure work.”
Disappointing well results and issues around permitting and cost are among the reasons for the less positive outlook, he believes. “On the positive side, we have had a very good experience with the labor force. They are reliable, health-, safety- and environment-minded people that we can employ in other markets.”
The company recently moved a rig into Spain to drill for unconventional gas and has some shale gas operations in the UK as well, but challenges in Western Europe continue to be around permits and regulations. “There are other global shale markets we’re currently investigating for growth, but it is still far too early to say what the potential is in those countries,” Mr Rendon said.
KCA DEUTAG has 66 land drilling and workover rigs globally, with conventional markets in Russia, the Middle East and North Africa being the biggest areas of operation. Utilization is high, and prospects for newbuilds are positive, Mr Rendon said, although the company is not building rigs on speculation.
In the UK, Cuadrilla Resources has updated the timetable for resuming operations at its exploratory well site in the Bowland Shale to 2014 to accommodate modifications in environmental impact assessments of the proposed drilling, hydraulic fracturing and flow-testing program. Cuadrilla is also proposing to strengthen its exploration program by adding several temporary exploration sites this year and next to assess gas flow rates, according to a statement released by company CEO Francis Egan in March.
Cuadrilla’s drilling operations in the field in northwest UK were suspended in May 2011 following two small earthquakes with epicenters near the drilling site. In December, the UK Department of Energy and Climate Change announced that hydraulic stimulation could resume but under strict guidelines.
Prior to the 2011 suspension, PR Marriott Drilling, the largest deep onshore drilling contractor based in the UK, had drilled three wells as part of their alliance with Cuadrilla Resources, and Cuadrilla had fractured one to determine the technically recoverable reserves in the field. The British Geological Survey is expected to revise its estimates of shale gas resources in the UK from 5.3 Tcf to between 1,300 and 1,700 Tcf, an increase of more than 200 times and more than 10 times the reserves known to exist under the UK’s part of the North Sea, according to John Beswick, director for PR Marriott Drilling. “It’s important to remember that UK is an island, so whatever is onshore extends offshore as well,” he said.
In comparison with many US plays that are relatively thin, the Bowland is characterized by a thick shale, suggesting the potential for multilateral wells, he noted. “Development will depend on getting the right engineering, but for now, the biggest challenges center around gaining local governmental approval to proceed and resolving environmental issues related to seismic activity, water management, climate change and chemical disclosures in the heavily populated scenic region. The tremendous resource potential in this play could make Britain energy self-sufficient – if there is the political will to allow its development,” he said.
APEX and APEX WALKING are registered terms of Patterson-UTI Drilling; APEX-XK, APEX-SK 1000 and APEX-XK 1500 are trademarked terms of Patterson-UTI Drilling. Military-Friendly Employer is a registered term of GI Jobs. ShaleDriller is a trademarked term of Independence Contract Drilling.
By Katie Mazerov, contributing editor