Production from unconventional reservoirs, particularly shale, has been a boon to U.S. domestic natural gas stockpiles.
It’s a blessing that has triggered a curse or two over time.
Engulfed in the thrill – and profits – of it all, the operators in a sense got ahead of themselves, producing extraordinary volumes right on the cusp of unexpected plummeting demand.
Only a few years back, operators flocked into the Haynesville shale gas play in North Louisiana, sometimes forking over $25,000 per acre lease payments as the ensuing drilling boom got under way.
No more. Today, royalty check amounts, field activity, etc., have dwindled. In DeSoto Parish, the core area of the Haynesville play, the drilling rig count plunged from 54 a year ago to 24 as of the second week in March, according to Baker Hughes Inc.
But in this highly cyclical industry, this type situation typically is best viewed as a hiatus.
Gas-intensive plays (such as the successful Fayetteville Shale and the famed Barnett Shale) are temporarily out of the limelight, but wet gas, or natural gas liquids, and oil areas are hot. Some high profile plays, e.g. the Marcellus, which stretches across Pennsylvania into New York, have a sizeable store of both.
Certain liquids-rich unconventional plays are said to hold particular appeal.
Here’s a brief look at the North America shale plays:
The Avalon Shale sits atop the Bone Spring formation in the Delaware Basin in the Permian Basin’s westernmost area.
The Avalon-Bone Spring play at times is called simply the Avalon Shale play, which, in turn, is often dubbed the Leonard. Typically, operators have drilled through the Avalon in search of other reservoirs, yet Avalon potential has been recognized for some time.
In some places, the interval is two layers of shale separated by a limestone layer.
An operator not long into the play in 2010 stated the production stream in this particular accumulation is an even three-way split between crude oil, NGLs and residue gas.
The Bakken Shale oil play in Montana and North Dakota continues to be a star attraction in the oil shale arena, where it’s been likened to another Saudi Arabia. The widespread Upper Devonian-Lower Mississippian Bakken formation consists of an upper and lower shale member and a mixed siliciclastic carbonate middle member.
The middle section is the prime target of the wells that encounter it about 10,000 feet deep, prior to turning horizontal into the brittle dolomite where multi-stage hydraulic fracturing is applied for more efficient production.
The Bakken extends into Saskatchewan and western Manitoba, where it is also productive.
The Barnett Combo play in Texas’ Montague and Cooke counties establishes an avenue toward increased oil production rather than natural gas. A well-defined oil window has always been a part of the now-famous Mississippian-age Barnett Shale play, but operators chose to concentrate on the natural gas areas.
The Combo play actually produces a somewhat balanced mix of oil, natural gas and natural gas liquids.
The resource base is said to be one of the world’s largest, with oil-in-place ranging from 40 to 200 million barrels equivalent per square mile. Numerous vertical wells having long production histories were drilled.
The Leonardian-age Bone Spring formation, which spreads into west Texas, has gone through several cycles of fairly sub-par production via vertical wells.
The Bone Spring series includes first, second and third Bone Spring sands and corresponding carbonates, and the shallower Avalon Shale, which also stands on its own as a separate play in some instances.
The initial targets in the Bone Spring were conventional sandstones. Wells then tapped into carbonate lenses and, ultimately, low permeability sandstones. Owing to horizontal drilling technology combined with hydraulic fracturing, very thin sands and other facies are now being produced.
The Cana Woodford shale is located in western Oklahoma, and the area has reportedly become a respectable size oil play. Even though the play is mostly liquids-rich with oil, natural gas is also found.
According to Devon Energy, the Mississippian-age Cana is the world’s deepest commercial horizontal play with TVDs 11,500 to 14,500 feet and MDs of 16,700 and 19,000 feet.
The Cana Woodford is considerably deeper and more expensive to reach than the Arkoma Woodford to the east. It’s said to be one of the most economic shale plays in North America, owing to high volumes of condensate and other pricey liquids.
The Cretaceous-age Cardium shale is a sand/shale formation that occurs in Alberta and extends into eastern British Columbia and south into Montana.
Of the 12 billion barrels of oil-in-place estimated by Canada’s Energy Resources and Conservation Board, about 1.5 billion barrels have been produced via vertical drilling technology.
The Cardium forms a sizeable stratigraphic trap in its eastern shaleout, creating Canada’s largest conventional onshore oil field, Pembina, discovered in 1953.
Parts of the Cardium are undergoing waterflooding, and horizontal multi-fracture drilling technology gets credit for stimulating production today.
Operators are said to be extending the lengths of the laterals, implementing more hydraulic fractures and getting better production and well results on a month-to-month basis.
The Upper Pennsylvanian Cleveland formation can be best described as a tight gas sand made up of fine-grained clean sands frequently interbedded with thin shale.
The Cleveland was discovered in the 1950s as players explored for deeper Morrow objectives. It occurs throughout much of the northeastern Texas panhandle and western Oklahoma.
The formation was initially developed using vertical wells with hydraulic fracturing. Horizontal drilling is today’s MO as a means to maximize production potential of the wells and minimize completion expense.
Despite the high oil volumes registered on initial tests and their general classification as oil wells, horizontal Cleveland production on a BOE basis is about two-thirds natural gas, according to AAPG member Dan Boyd, petroleum geologist at the Oklahoma Geological Survey.
The Eagle Ford shale play spans a geographic area in south Texas ranging from far western Webb County northeastward to Gonzales County. The shale is long known for sourcing hydrocarbons to Austin Chalk fields as well as the renowned East Texas Field.
It produces a liquids-rich gas stream as well as oil in certain areas of the play. Generally, the oily part is the northern area where lower pressures rule. The play’s mid-section reportedly harbors the condensate, or wet gas, window with a sweet spot of high concentrations of light oil. Much drier gas is found in the deeper section of the shale to the south in the play.
The Devonian-Mississippian Exshaw formation correlates with the Lower and Middle Bakken zones in Canada’s Alberta and British Columbia. In fact, the two are often referred to as the Bakken/Exshaw interval, which usually is no more than perhaps 40 meters thick.
The Exshaw petroleum system is said to include the over- and underlying limestone reservoirs of the Banff and Big Valley, respectively, which are the most likely candidates for horizontal drilling.
The Exshaw transitions to the Bakken at the Alberta-Saskatchewan border.
The tight sands Granite Wash play covers parts of western Oklahoma and the Texas Panhandle, covering an area about 160 by 30 miles.
It’s been a drilling target and/or pass-through zone for decades using vertical wells. Today, horizontal drilling and completion techniques are proving invaluable to bring up respectable-plus production, reduce dry hole risk and to render some reservoirs highly economic.
Granite Wash reservoirs span almost the entire Pennsylvanian System through the Lower Permian. They are comprised of thick, low permeability sediments shed from the Wichita Uplift. The Wash changes both vertically and horizontally across the play.
The Marcellus Shale member of the Appalachian Basin’s Devonian black shales spans a distance of approximately 400 miles, trending northeastward from West Virginia and into New York.
It’s a play having something for everyone in that there are wet gas areas, dry gas areas and areas of varied geological complexity.
Range Resources geologists Bill Zagorski and Martin Emery, both AAPG members, say that one can basically call the two major core areas a northeast dry gas play and a southwest combination NGL/dry gas play.
The Mississippi Lime in northern Oklahoma and southern Kansas looks really good with an oil ratio typically above 50 percent.
Vertical fractures occur in this regional carbonate deposit, which lies beneath the productive Atoka and Morrow sands and above the Devonian-age Woodford and the older Silurian-age Hunton.
Vertical wells have been drilled in this area for decades, where the Lime has yielded only marginal production.
Reservoir quality tends to be poor owing to minor porosity and permeability yet greater than most shale plays. Even so, industry players believe there are sweet spots that will be quite lucrative.
Recent horizontal drilling has yielded some very successful wells.
The Miocene-age Monterey shale in southern California has sourced almost all of the oil in California. The Monterey, which is estimated to contain more than 500 billion barrels of oil-in-place, has been produced in one fashion or another for more than 100 years.
It’s now being viewed as an unconventional play ripe for application of today’s new tools and technologies.
Reportedly, the Monterey producing gross column is hundreds of feet thick at Oxy’s Elk Hills field, which the company produces via vertical wells.
The Monterey also produces offshore California, e.g., the South Ellwood field discovered in 1997.
The Lower Triassic Montney formation is principally a siliciclastic-dominant unit found west of Edmonton in west-central Alberta and northeast British Columbia.
Of the Montney’s four distinct pay zones, the upper and lower intervals are said to be the most prolific producers.
It has been reported to be one of the largest economically viable resource plays in North America, with an estimated resource size of 50 Tcf.
Long-viewed as a drill-through zone, the Montney came into its own once horizontal drilling was implemented.
The Late Cretaceous Niobrara Shale extends across New Mexico, Colorado, Wyoming, Kansas, Montana and both North and South Dakota.
The industry has long known that oil was present. It took a combo of horizontal drilling and staged hydraulic fracture treatments, to free the hydrocarbons long trapped in the shales, making the play economic.
The Denver (DJ) Basin in southeast Wyoming and northeast Colorado has been an extremely active area in the Niobrara play.
The Pennsylvanian-age Tonkawa sand in north-central Oklahoma and south-central Kansas is a fluvial dominated deltaic reservoir.
Drilling depths between 2,200 and 4,200 feet are the norm, but earlier drilling focused on deeper, more productive targets before operators acquired a better understanding of the shallow accumulations.
In the Blackwell Field area in Kay County, north-central Oklahoma, the Tonkawa B sandstone is the main oil and gas reservoir.
The Tuscaloosa Marine Shale extends more than 2.7 million acres across central Louisiana, reaching into southwestern Mississippi. The deep, high-pressure shale occurs between the upper and lower units of the Cretaceous Tuscaloosa formation.
The Marine Shale has thrown oil for years, piquing operators’ interest as they drilled through it targeting deeper horizons. Owing to available advanced technology to drill and complete shale zones, it now appears quite possible to commercially produce some of the estimated seven billion barrels held by this particular shale.
The play’s western area usually is referred to as the Louisiana Eagle Ford, as the shale there is similar in age and lithology to the liquids-rich Eagle Ford formation in Texas.
The Late Ordovician-age Utica Shale in the Appalachian Basin occurs much deeper than the geologically younger Marcellus Shale and extends beyond the geographic limits of the highly productive Marcellus.
The Utica is the primary source rock for a number of conventional hydrocarbon-bearing reservoirs throughout the Appalachian Basin.
The impetus for early activity to focus in Ohio is the liquids window found in the eastern part of the state, as well as Kentucky and reaching into Ontario and the St. Lawrence Lowlands of Quebec.
The Cretaceous-age Viking oil play is a series of legacy oil pools reaching from central Alberta to southwest Saskatchewan. It’s a known conventional play produced via vertical drilling using older technology since its discovery in 1957.
The Viking formation is estimated to contain about six billion barrels of original-oil-in-place.
Horizontal wells with multi-stage hydraulic fracturing have revitalized the play. However, its continuous, or blanket, nature has encouraged the mindset: drill a well, find oil.
The Lower Permian-age Wolfberry play in the Midland Basin is a combo of the packed-limestone Wolfcamp and the overlying Spraberry sandstone, often called the Spraberry-Dean to include the underlying Dean sandstone. The Spraberry has long been a go-to reservoir given that it’s pretty much fail-safe, essentially guaranteeing production – often in small volumes – over long periods.
The Permian-age Wolfbone (Delaware Basin) is a combo of the limestone/sandstone Wolfcamp and Bone Spring formations. The Wolfbone reportedly is not a development like the Wolfberry, but there are said to be some look-alikes in the geological sense.