The shale gas business is booming in the US: GlobalData breaks down the most exciting areas for prospecting, and considers some of the challenges to profitability facing the major companies involved in finding and tapping reserves across the continent.
Bakken Shale, US and Canada
Bakken Shale straddles the US and Canada. In the former, it is located in Montana and North Dakota, while in the latter it is found in Saskatchewan and Manitoba. It is a Devonian shale, within the central and deeper portions of the Williston Basin. Its lithology is divided into three sections: upper, middle and lower. The combined thickness of the three shales is 130ft (40m). The upper and lower shales are thermally mature, highly organic and over-pressurised.
These two shales are the generating source and act as reservoirs for crude. The composition of the middle shale varies from a silty dolomite to shale limestone or sand. It also acts as a reservoir for oil, and plays an important role in commercial production.
The oil and gas yield from the shale increased from 1.3mmboe in 2006 to 114.9mmboe in 2009; by 2011 production had nearly doubled to 203.6mmboe.
In North Dakota, the existing pipeline capacity has not been sufficient to handle this increased production, which resulted in the sale of Bakken crude at lower prices than West Texas Intermediate (WTI) prices. This prompted some of the Bakken operators to start transporting crude using rail cars, reducing the gap between the prices of Bakken crude and WTI crude.
The operators with the most net acreage in the Bakken Shale are Continental Resources (1,200,000 acres), Crescent Point Energy (768,000 acres) and Whiting Petroleum (729,732 acres). The EUR per well of Continental Resources in Bakken is 603 thousand barrels of oil equivalent (mboe) per well, and the cost per well is $8 million.
The main geological challenge facing Bakken Shale is that of establishing ideal well spacing. The optimal density of the shale also remains unknown. Any change in upward or downward well densities has the potential to have a significant effect on the economics of operations.
The other challenges that need to be overcome are competition among operators for water, and regulations concerning fracking operations and natural gas flaring. The Williston Basin flares about 30% of its natural gas production, as transport economics often mandate flaring over sales.
Barnett Shale, US
Barnett Shale is located in Texas and is situated within the Fort Worth Basin. It spans Dallas and western and southern Texas. The Mississippian-aged shale is located at depths of 5,400-9,600ft (1,646-2,926m). The geology of Barnett Shale is characterised by sedimentary rocks.
The productive part of the shale measures 5,000 square miles (13,000km2) and spans the west and south of Dallas, covering 24 counties.
Barnett Shale is classified into two areas: core and non-core. The non-core area is again classified into Tier 1 and Tier 2. The Newark East field, in the core area, is responsible for the majority of production in the shale formation.
The field is spread across the Denton, Wise and Tarrant counties, which is the core area. Barnett is thickest and deepest in the core area, implying that most of the gas in the shale is located in that area.
The Tier 1 area lies south and west of the core location and is in the Johnson, Hood and Parker counties. The Tier 2 area is situated to the west and south of Tier 1 and is in the Jack, Erath and Palo Pinto counties. Tier 2 is the least developed area in the Barnett Shale.
The Barnett Shale is the largest exploration play in the eastern US and is economically important to Texas. Oil and gas production from the shale increased from 122.7mmboe in 2006 to 344.5mmboe in 2012 at an AAGR of 17.2%. Natural gas, meanwhile, accounts for most of the production in the shale.
Among the operators in Barnett Shale, Devon Energy and EOG Resources are the highest net acreage holders, with 613,000 acres and 430,000 acres, respectively. Devon Energy’s EUR is 4bcfe per well, and its cost per well is $3-4 million.
Like other shale plays in the US, Barnett Shale faces a number of challenges, including varied drilling conditions and adverse weather conditions.
The northern part of Barnett Shale’s core has a thick layer of Forestburg limestone, which requires two fractionation stages. Pollution from the fluid used in fracking and the use of large quantities of fresh water are concerns for environmental groups.
The use of fresh water became a serious issue during the 2011 drought in Texas. The gas pipeline capacity at the shale is also becoming saturated and requires fresh investment in order to thrive.
Eagle Ford Shale, US and Mexico
Eagle Ford Shale is a sedimentary shale rock formation, in the US and Mexico. It is about 400 miles (64km) long and 50 miles (80km) wide, extending across east and south Texas from the Mexican border. It is spread across 23 counties, of which the most important locations are Gonzales, Webb and De Witt.
The Eagle Ford Shale belongs to the Cretaceous age and is sandwiched between the Austin chalk and Buda lime formations. It has high carbonate content and is brittle when compared with other shale formations.
It also has a high silica content, with an average clay content of 11%. The thickness of the shale is 330ft (101m) in some areas, and the production depth varies from 4,000 to 15,000ft (1,219 to 4,572m).
Oil and gas production at Eagle Ford Shale started in 2009, with 3.7mmboe being produced that year. Production increased rapidly from 2009 to 2012, at an AAGR of 147.2%, reaching 127.2mmboe in 2011 and 306.3mmboe in 2012.
Eagle Ford Shale has evolved as a shale oil play, and attracted the attention of both domestic and foreign companies. The operators with the most net acreage in the Eagle Ford Shale are EOG Resources (639,000 acres), BP (450,000) and Chesapeake Energy (380,000). Hydrogen sulphide deposits exist below the Eagle Ford Shale and need to be avoided when drilling. The layer (upper member of the Lower Eagle Ford) immediately above the targeted reservoir rock is bentonite-rich and must also be steered clear of.
If bentonite is subjected to high water pressure, it can cause the borehole to become unstable and possibly collapse.
A rapid increase in production could choke pipeline capacity and increase transportation costs. Saturation of pipeline capacity has already prompted EOG Resources to transport a substantial portion of its production via rail.
Marcellus Shale, US
Marcellus Shale is mainly a natural gas play and is in the states of Pennsylvania, New York, Ohio, and West Virginia. With an area of more than 104,065 square miles (269,527km2), it is one of the largest and most highly concentrated natural gas resource areas in the US.
Drilling activity at the Marcellus Shale is mostly concentrated in West Virginia and Pennsylvania, and the Pennsylvania section has emerged as one of the fastest-growing gas plays in the US. Some of the major companies operating in the shale are Chesapeake Energy, Shell, Range Resources and National Fuel Gas.
Marcellus Shale lies within the Devonian Black Shale field and is estimated to contain 168-516tcf of natural gas. It is an Argillaceous Mudstone of the Middle Devonian epoch. Marcellus contains clay, silica, calcite and carbonate.
The depth of the shale reaches 8,500ft (2,591m), and drilling activity is primarily concentrated in areas where depth is greater than 2,000ft (610m).
The depth of an average well is 7,000ft (2,134m), and the average thickness is 350ft (107m). The average pressure is 4,000psi, and the pressure gradient ranges from 0.25 to 0.4psi/ft. The shale has a porosity of 0.5-2.5% and a permeability of about 1,000 nanodarcys (nD).
One of the reasons for the fast development of Marcellus Shale is its proximity to the largest gas-consuming regions in North America. The development of Marcellus gained momentum in the 2000s and oil and gas production has increased from 1.3 mmboe (million barrels of oil equivalents) in 2006 to 342.2mmboe in 2012 at an average annual growth rate (AAGR) of 92.5%.
Among the companies operating in the Marcellus Shale, Chesapeake Energy has one of the highest net acreages, at 1,800,000. The estimated ultimate recovery (EUR) per well for Marcellus is 10.4 billion cubic feet equivalent (bcfe), and the cost per well is $6.7 million.
The main challenges faced by the companies at the Marcellus Shale are low permeability, environmental concerns, and legal cases over endangered species. The state of New York issued a moratorium on drilling in the New York section of Marcellus Shale in 2008.
Niobrara Shale, US
The Niobrara Shale is located across the western US. It covers an area of 8,400 square miles (21,756km2) and is primarily found in the Rocky Mountains of Colorado and Wyoming. The shale is located within the Denver Julesburg (DJ) Basin and Powder River Basin. The majority of drilling and exploration takes place in the DJ Basin, primarily in Weld County, Colorado.
The Niobrara formation was laid down during the Cretaceous period, about 85 million years ago. It belongs to the Codell-Niobrara interval, owing to its stratigraphic proximity to the Codell Formation.
The interval consists of the Niobrara Formation and the Codell Sandstone Member of the Carlile Shale, which also belongs to the cretaceous period. Niobrara is an organic-rich shale interbedded with brittle chalk beds. The thickness of the shale ranges from 150 to 1,500ft (46 to 457m). The brittle carbonates interbedded within the shale tend to have very high porosity (40-50%) and low permeability (0.1-3.0mD), increasing the Niobrara Shale’s overall porosity to about 5-10%.
Niobrara’s thermal maturity varies, resulting in high yields of oil and gas. Niobrara has the potential to emerge as the next big oil play in the US. The initial wells drilled at the play have shown positive results. Gross crude and natural gas production at the Niobrara Shale increased from 8.6mmboe in 2007 to 26.4mmboe in 2012 at an AAGR of 22.4%.
Crude oil production increased from a mere 0.5mmboe in 2007 to 11mmboe in 2012 at an AAGR of 61.8%. Natural gas production increased from 48.6bcf (billion cubic feet) in 2007 to 92.6bcf by 2012 at an AAGR of 12.9%. Colorado accounts for more than 85% of production at the Niobrara Shale.
Among the companies operating in the Niobrara Shale, Anadarko has one of the highest net acreages, at 1,190,000 acres. Anadarko’s EUR at the shale is 350mboe per well. The cost per well of the company is $4.3 million per well.
Niobrara Shale development faces several unique challenges. It is heavily concentrated in northern and central Colorado, owing to disappointing production figures in certain regions. The operators at the play are testing new techniques for drilling, because of the size and varying geology of the shale.
Some of Niobrara’s potential drilling sites are in populated areas and urban environments; therefore, access to land is a problem. Hunting and wildlife restrictions and rugged terrain, as well as the risk that fracking will cause water pollution, are some of the other challenges.
Tuscaloosa Marine Shale (TMS), US
TMS is an oil and gas shale play, in the Louisiana and Mississippi states. After the Haynesville Shale play, it is the second-most important play in Louisiana. It is also called the Louisiana Eagle Ford, owing to its geological similarities with the Eagle Ford Shale play.
TMS spans 19 parishes in south and central Louisiana, and six counties in south-west Mississippi. The shale play covers an area of about 2.7 million acres and is spread over a 50-mile (80km)-wide band.
It fully, or partly, covers Vernon, Beauregard, Allen, Rapides, Evangeline, Avoyelles, St Landry, LaSalle, Catahoula, Concordia, Pointe Coupee, East Baton Rouge, St Helena, Livingston, Tangipahoa, St Tammany, Washington and East and West Feliciana, in Louisiana, and Adams, Franklin, Wilkerson, Pike, Amite and Walthall, in Mississippi.
TMS is an organic-rich shale and belongs to the Cretaceous period. Its formation comprises three stratigraphic units.
The middle unit of the formation is predominately shale. Drill depths at the TMS range from 9,000 to 17,000ft (2,743 to 5,182m). The formation thickness varies from 500 to 800ft (152 to 244m).
TMS is evolving as an emerging liquid-rich shale play in the US. It is rich in brittle silica, which can be easily fractured and helps to decrease drilling costs. TMS witnessed some drilling in the past.
Nevertheless, the interest of companies in the play has been renewed due to the presence of substantial quantities of oil, the rising prices of oil and recent advances in drilling technologies.
Some of the major companies operating in the TMS are Goodrich Petroleum and Encana Corp. Goodrich Petroleum had gross acreage of 158,214 acres and net acreage of 134,244 acres in the TMS at the end of 2012.
It had two operating wells at the play at the end of 2012. Encana had 311,000 gross undeveloped acres (294,000 net acres) in TMS at the end of 2012. The company drilled about seven net horizontal wells in 2012. The average effective length of the net wells was 5,800ft (1,768m).
The major companies operating in the region are optimistic about the commercial potential of the play. However, the play could still require the drilling of multiple wells in order to confirm its economic viability. The proper selection of drilling technologies has been identified as critical to success in this area.
Utica Shale, US and Canada
Utica is an oil and gas-producing shale, in the US and Canada. In the US, it is located in the states of Ohio, Pennsylvania, New York and West Virginia. In Canada, it is located in Quebec. Utica gets its name from the city of Utica, New York, where the shale is visible on the surface.
The Utica Shale formation was formed during the Taconic orogeny (late Ordovician period). It mainly contains dolomite, clays, quartz and calcite. The average depth to the top of the formation is in the range of 3,000 to 11,000ft (0.57 to 2.091 miles).
The deepest areas in the shale are situated along the eastern boundary of the formation. The thickness of the shale reaches about 1,000ft (0.19 miles) in certain areas. The total organic content is in the range of 1.5 to 3.0%. Its porosity and thermal maturity ranges from 3.0 to 6.0% and 1.1 to 4.0% respectively.
Commercial production at the Utica Shale play started in 2012 and is expected to increase substantially. Ohio accounts for most of the drilling activity in the US part of the shale, owing to its high-liquid potential. In Canada, the Quebec government has imposed a moratorium on shale drilling until an environmental assessment on the shale industry has been completed.
Among the operators in the Utica Shale, Chesapeake has one of the highest net acreages, at a million acres. It costs Chesapeake on average $6.0-7.5 million to drill and complete a well. The Utica Shale operations of Chesapeake are primarily located in Ohio.
Utica is a complex play with high geological variation, which increases the challenge of understanding the reservoir’s behaviour. The lack of sufficient transport infrastructure in the US part of the shale is also preventing companies, including Chesapeake, from realising their full potential in the area.
In Canada, the Quebec Government is proposing a high royalty regime for the province’s shale industry, which will decrease the profitability of companies and discourage investment.
Wolfcamp Shale, US
Wolfcamp Shale is an emerging, liquids-rich unconventional play in the Permian Basin, in western Texas and south-eastern New Mexico. It is suitable for companies that want to focus on liquids-rich plays, as natural gas prices remain relatively low in the US. Some of the key operators of the play are EOR Resources, Approach Resource, Cimarex Energy, Devon Energy, Pioneer Energy and Linn Energy.
The Wolfcamp Shale formation measures 200 miles (322km) wide and 100 miles (161km) long. Its depth ranges from 7,000 to 10,500ft (2,134 to 3,200m).
Its net pay thickness is 20ft (6m), and its porosity value is 9-12%. Wolfcamp Shale has three zones, of which the top and bottom zones are productive.
The thickness of these is estimated to be as much as 1,200ft (366m), and the bottom zone is the most productive of all three. The latter has 4-45ft (1.2-13.7m) of organic limestone and has an oil water contact at 5,370 ft (1,637m, subsea).
Though Wolfcamp has long been known to hold oil and gas, it remained mostly unproductive until the mid-to-late 2000s, owing to its low permeability. However, with the development of vertical drilling and hydraulic fracturing, production from the shale has increased rapidly and Wolfcamp is now one of the most active plays in the US. In 2013 alone, hundreds of wells were drilled; the development densities at the shale range from 40-140-acre spacing.
Among the companies operating in the Wolfcamp Shale, Pioneer Energy has the largest net acreage, at 935,800, in the Midland Basin. It also has one of the highest rig counts, at ten. In 2012, it drilled more than 400 vertical wells.
The challenges faced by the companies operating in the Wolfcamp Shale are lack of proper infrastructure and high operational costs. Pioneer Energy, one of the most active players in the shale, is facing high electricity costs, which is affecting profitability. The lack of water resources in the Midland Basin is also a difficulty.
Other problems include inconsistent rock lithology and increasing environmental regulations in the Permian Basin.