Oil-Prone Shales

Right now, oil is the industry’s golden boy, blessed with a glowing future. Natural gas is like the vaguely seedy brother-in-law that nobody in the family wants to talk about.

It’s oil’s day, and given the fundamentals of its markets, it looks like that day will be a long one. Explorers have turned toward oil with a passion, and the newest focus is on oil-prone shales. These are shales that can produce oil, distinctly different from the oil shales of old. The latter, most notably the Eocene Green River formation of western Colorado, are really pre-oil shales. Kerogen-rich, they are thermally immature and require intensive processing before they will yield products. Commercial production from traditional oil shales likely lies decades into the future.

Today’s target goes by a bushel of names: oil-prone shale, shale oil, tight oil, low-perm oil, or oily shale. While there’s no consensus yet on the best name for these reservoirs, we are talking about shales that have the ability to produce oil in commercial quantities now.

The shales leading this new parade are California’s Monterey and North Dakota and Montana’s Bakken. These are shale reservoirs that are fully and unquestionably economic, and their success has inspired fervent enthusiasm for analogous plays. While prospective targets occur in the Midcontinent and Gulf Coast regions as well, a great deal of activity has focused on prospective shales in the Rocky Mountain region.

Evolving understanding

Myriad questions about both reservoir and oil qualities swirl about the new generation of shale-oil plays.

“Shale-oil systems are as complicated as shale-gas systems and are generally more problematic,” says Dan Jarvie, president, Worldwide Geochemistry, and currently visiting scientist at the Institut Français de Petrôle in Rueil-Malmaison, France. “That’s due to the nature of the oil, which can be highly variable, and the rock matrix.”

The Barnett shale, which produces small volumes of black oil in Montague County, Texas, is totally different from the Bakken shale, which produces high volumes of light oil in North Dakota and Montana. And both are different from the Monterey system, which makes copious volumes of low-gravity oil in coastal California.

Jarvie recognizes three main types of shale-oil systems: highly fractured and permeable mudstone; tight mudstone; and hybrid systems.

The Santa Maria Basin’s Monterey falls into Jarvie’s first category. At this locale, the shale is highly fractured and quite permeable, and open fractures within the shale provide storage capacity. Key issues in this type of system are oil saturation and oil quality. The oil-productive Kimmeridge shale in England’s Devonshire region resembles this type.

The Barnett shale is an example of a tight mudstone system, as is likely the Gulf Coast’s Tuscaloosa Marine shale. This type presents the most difficult case for potential production, as the mudstones have very low porosities and ultra-low permeabilities. “It’s incredibly hard to break oil free in tight shales like the Barnett,” says Jarvie. “Organic-rich mudstones have a high adsorption affinity for oil.”

Additionally, a tight system without fractures will only have an in-situ charge, which is generated as kerogen converts to oil and oil migrates from the kerogen into the source-rock matrix.

In happy contrast, hybrid systems exhibit much more favorable reservoir characteristics. In hybrid systems, source rock is interbedded with conventional reservoir rocks, such as low-grade sands or carbonates. The conventional reservoirs can also be nearby.

“Hybrid systems appear to have the best potential for shale-associated oil production,” says Jarvie. The Northern Rockies’ Bakken and South Texas’ Eagle Ford both fall into this category, and possibly the Lower Toarcian shale in France’s Paris Basin.

Hybrid systems have both an in-situ charge and a charge from primary migration, which occurs when hydrocarbons move out of the source rock. Both retained and expelled hydrocarbons can therefore be recovered. Furthermore, hybrid systems often contain carbonates, and these can be beneficial as well. “When carbonate is present in a shale system, everything changes,” he says. “Carbonates do not have an adsorption issue, and oil will flow freely from a charged carbonate once stimulated.”

Several geochemical processes are extremely important for charged shale-oil systems, says Jarvie, including organic-matter conversion and the precipitation and dissolution of carbonates. Immature organic matter releases water, carbon dioxide and other components as it decomposes. Of interest is acid generation, because acid appears to play a role in creating migration conduits as well as potentially creating secondary porosity in carbonates.

It’s also important to remember that there can be multiple pulses of expulsion and migration from source rocks. Finding a shale in the oil window does not necessarily mean that the shale will contain producible oil. It’s important to screen samples to see if they have sufficient oil saturation.

The interplay of many factors determines which shale systems will break picks and which will become commercial reservoirs. Each system has to be evaluated carefully. Geological, geochemical, petrophysical and seismic data may be needed, but much work can be completed on available samples prior to leasing, committing capital or spudding a well.

“If we can get the oil out of these various systems, we are looking at tremendous resources,” says Jarvie.

California precedent

The most prolific producing shale to date is southern California’s Miocene Monterey.

Denver-based independent Venoco Inc. is in the midst of developing a play in the shale, which is the source rock for California’s gigantic oil fields, including Midway-Sunset, Belridge South, Kern River, Cymric and Elk Hills.

All told, the Monterey has sourced about 38 billion barrels of recoverable oil, largely trapped in sandstone reservoirs. In the San Joaquin Basin, the shale can be up to 8,000 feet thick, with outstanding total organic carbon (TOC) content and just the right thermal maturity.

And there is much more: “We think the Monterey is capable of sourcing about 290 billion barrels of oil in its current setting,” says Mike Wracher, Carpinteria-based vice president, exploration.

That makes for a world-class target.

The Monterey itself has already delivered substantial production. Fractured-shale production started in the Santa Maria Basin in 1900. A hundred years ago, the Monterey made heavy oil in astonishing quantities, estimated to total some 1.79 billion barrels.

Today, by importing modern-day shale production practices, Venoco thinks it has the ability to access the rich lode of in-place oil that still resides in the Monterey.

In 2006, the company began to lease specifically with an eye to exploring the Monterey with the emerging shale-play concepts. Surprisingly, for such a high-grade and long-time producing reservoir, acreage was open. That’s because California’s oil business has been dominated by major oil companies since the beginning of the 20th century, when they acquired the great old giants. The majors still produce these fields, but they have not spent much capital or energy on wildcatting in decades.

Mike Wracher, above, vice president of exploration for Veneco Inc., is exploring southern California's Monterey shale with modern shale-play concepts.

Furthermore, California’s fearsome reputation as a difficult state in which to do business also isolated it from the rest of the Patch, particularly from independents in other states.

“As a result, large portions of southern California are lightly explored,” says Wracher.

To date, Venoco is approaching 100,000 net acres in 25 project areas spread across southern California, from the coast to the San Joaquin. Its risked resource potential, assuming a recovery factor of 5% and 50% success, is an impressive 500 million barrels.

Many faces of the Monterey

The Monterey is a complex and fascinating target. It offers diverse reservoir styles, producing from fractured, structural fields, from matrix-dominated reservoirs including hybrid silt- and clay-rich varieties, and from diagenetic traps, says Wracher. Within the Monterey, three distinct rock types are present: Opal A, Opal CT and quartz. These can occur together in the same wellbore, and can vary rapidly between wells.

The Monterey was deposited as diatomite, sediments made up of diatoms. Basically an algae with a siliceous shell, unaltered diatomite is the Opal A phase. As diatomite is buried and pressures and temperatures increase, it alters to cristobalite tridymite, a partially ordered form of quartz. That’s the Opal CT phase in industry jargon. As lithification continues, the Monterey changes into a quartz phase.

“The Monterey produces from all three phases,” says Wracher. “As it moves through the phases, porosities are decreased and water is expelled. Oil generation begins at quartz phase and a little beyond.”

A world-class source rock and a producing reservoir, the Monterey shale is present in California's Santa Maria, Ventura, Los Angeles and San Joaquin basins.

In addition to diatoms, varying amounts of carbonate organisms and clastics are part of the Monterey, depending on area. Deep marine sands, limestones and clay and mud shales are all present. To add another layer of intrigue, the Monterey has gone through different pulses of oil generation, and indeed is still actively generating hydrocarbons. Heavy oil and light oil have coursed through the region. Finally, coastal California is a tectonically active margin, so all sorts of folding, wrenching, compressive and expansive episodes have broken and twisted its subsurface. Activity, as any earthquake-savvy resident can attest, is ongoing.

The intricacy of the system presents a banquet of opportunities. The Monterey offers an incredible variety of rock types and potential hydrocarbon traps.

Offshore California, the Monterey is mainly in the quartz phase and fields produce from highly fractured shales on structures. The offshore Monterey was discovered in 1969 at South Ellwood Field, an asset acquired by Venoco in 1997. The operator at the time planned to recomplete a Rincon well, but the Monterey started to flow behind casing. That kicked off the Monterey play in the Santa Barbara Channel, and a number of prolific fields were developed.

Just the western half of South Ellwood has produced 68 million barrels from the Monterey alone; individual Monterey wells average 4- to 5 million barrels apiece, and the largest well is expected to recover almost 20 million barrels. ExxonMobil’s Santa Ynez Unit is the largest Monterey accumulation—it has already produced more than 400 million barrels.

“The fractured reservoir play is more traditional. Oil migrates to the top of structures,” says Wracher.

In the San Joaquin Basin, the Monterey being produced is mainly in the Opal A and CT phases. Here, the formation is hydraulically fractured and waterflooded. At Elk Hills, the Monterey produces from a largely quartz phase dual-porosity, fractured reservoir; at North Shafter, the oil is present in a stratigraphic trap.

The North Shafter trap is particularly interesting. The field, discovered in 1995 by Texas Crude, and later sold to EOG Resources, sits on the basin’s east flank. It lies at the phase change from Opal CT to quartz, and is a classic diagenetic trap. The 14-million-barrel field produces from 45 wells, most of which are horizontally drilled and fractured using older technology. It provides an early analog for new-era shale explorers.

This year, Venoco plans an aggressive Monterey program. It will conduct development work at South Ellwood and Sockeye, another Monterey field it operates in the Santa Barbara Channel. A number of wells will be worked over at South Ellwood, and a pair of wells will be drilled and fractured at Sockeye.

Its exploration attention will be on the broader Monterey play. “Largely, we are working in the Opal CT and quartz rock phases,” says Wracher. “We’re looking for a variety of traps, including continuous matrix.”

Venoco has focused its Monterey program in areas of extensive well control. It has gone after structurally advantageous positions in regions with light, sweet oil. During 2010, it will drill and core five wells, primarily vertical; acquire 3-D seismic through its core areas; continue its G&G work; and keep leasing.

“We are looking at taking on a partner, which would allow us to accelerate our program,” says Wracher. If a partner is added, Venoco could drill as many as 16 wells this year. Given favorable results, it has more than 20 wells on the drafting table for 2011.

Bakken success

As successful as the Monterey has been, it was the Williston Basin’s Bakken that kick-started the industry’s surging interest in low-permeability oil reservoirs. A group of independent operators conclusively demonstrated that low-perm shale reservoirs could be highly economic, if just the right technology were applied.

“The Bakken play is working now in a huge way,” says Steve Sonnenberg, professor of petroleum geology, Colorado School of Mines, Golden, Colorado. “It’s essentially a newly commercial resource, a tight reservoir that can produce thousands of barrels of oil per day from a single well. And it’s because of horizontal drilling and multistage fracturing technology.”

The Bakken is thin but mighty. “These shales are world-class source rocks,” he says. “TOC content averages about 11% across the basin, and reaches above 30% in places.” Across the entire Rockies, the Bakken and its equivalents are far and away the richest source rocks.

There’s lots of excitement in the Bakken: many operators are at work, and they have been successfully expanding the play in new directions. Technology is evolving rapidly, making areas that seemed marginal a year ago now solidly commercial.

CSM is running a three-year Bakken Research Consortium that has generated excellent industry participation. The consortium and a concurrent $1.5-million Department of Energy/National Energy Technology Laboratory project are focusing on the stratigraphy, reservoir characteristics, fracturing, diagenetic history and provenance of the Bakken.

Participants are Anschutz Exploration, Discovery Group, Enerplus Resources, EOG Resources, Fidelity Exploration, Hendrix and Associates, Marathon Oil, Mike Johnson, Questar Exploration & Production, Red Willow Production Co., Samson Investment Co., Savant Resources, Statoil, Total, Whiting Petroleum and XTO Energy. The study is also supported by IHS Inc., MJ Systems and TGS-Nopec.

“We’re taking a petroleum system approach, looking at the Lodgepole, Bakken and Upper Three Forks,” says Sonnenberg, one of four principal investigators directing the research.

A significant charge of the consortium is the assessment of how oil is trapped in the Bakken. “We can say that there are significant changes in the types of traps in the Bakken,” Sonnenberg says. “One of the keys is not to get locked into a single model. We think several models are going to work in the Bakken, as in other unconventional resource plays.”

The consortium is winding up the first year of a three-year term. Initial work focused heavily in eastern Montana in the Elm Coulee area, and current efforts are centered in the Parshall area in North Dakota.

The third phase will study the new areas of production and expand coverage to the west. The group is quite interested in central Montana, where Bakken-age equivalents are present and prospective. Finally, the consortium will look at the feasibility of secondary and tertiary recovery techniques in the Middle Bakken. At present, recovery factors are between 5% and 10%, so the potential exists for huge gains.

Beyond the consortium, more shales await. “We’re also looking at expanding research into some of the other oil-prone shales in the Rockies,” says Sonnenberg. One CSM student is already working in the Mowry and two are investigating the Niobrara petroleum system. “We don’t have a consortium set up on those plays, but we are moving in that direction.”

Rockies shale potential

“We see oil-prone shales as the industry’s next major paradigm shift,” says Peter Dea, president and chief executive of Denver-based Cirque Resources LP. “We think we are on the cutting edge of these tight-oil reservoirs, including those from shale and dolomitic shale rocks.”

Privately held Cirque started up two years ago with the vision that oil-prone shales would soon become the country’s dominant play. “We certainly recognize that what’s been successful for us in our past public companies has been to put together large gas resource plays, in sands, coals and shales, and now we’re doing it in oil,” says Dea.

With that strategy in mind, Cirque assembled a small, talented team that has focused on different types of shales in the Rocky Mountain region. To date, Cirque and its joint-venture partners have leased more than 800,000 net acres, of which about 650,000 acres are net to Cirque.

“For our size company, we think we are unique in our focus on tight-oil resource plays.”

Steve sonnenberg, top professor of petroleum geology, Colorado School of Mines. Peter Dea, bottom, chief executive officer, Cirque resources LP.

Cirque chose the Rockies for a number of reasons. Geologically, it’s one of the major oil provinces in the Lower 48, and it is home to a wealth of shale potential. Furthermore, Cirque personnel have long experience in the Rockies. “In one way or another, we’ve been tripping over these shales for decades,” he says.

To begin, Cirque sought out shales that were recognized as important source rocks and that were known to be productive from vertical wells. “There are other shales that may be equally prospective, but we selected those that had demonstrated the capacity for commercial production.”

In its prospective shales, old vertical wells recorded production in a range from 10,000 to a couple of hundred thousand barrels of oil per well. While most historic Rockies shale wells were far from barnburners, a selected few have produced outstanding volumes of oil.

But Cirque isn’t hunting for areas where large-scale faults and fractures allowed oil to flow through shale reservoirs. Rather, it is looking for areas with simple tectonics where it can apply horizontal drilling and hydraulic fracturing technology.

“That’s the game-changer,” says Dea.

The company has zeroed in on basin-centered oil plays. “We call these the ‘small-crack’ plays,” says Rob Sterling, senior geologist. “We believe that microfractures that form by the generation of hydrocarbons are the essential element for success.”

Cirque looks for Type II kerogen in marine shales. It focuses on the hydrocarbon-generation window to determine the proper places to buy acreage; the plays it seeks are notable for being slightly to highly overpressured. Sterling points to fields in the Monterey shale in the San Joaquin Basin and Mowry shale in the Powder River Basin as models for Cirque’s prospects. “We are looking for brittle rock that is predisposed to expulsion microfracturing, and then we want to enhance that with hydraulic fracturing.”

To date, Cirque has defined 10 project areas. “We are putting together high-potential, company-building, scalable projects that fit the overall resource model,” says Dea. Once it has amassed acreage on a project—typically between 50,000 and 200,000 acres—it brings in a partner and starts to drill. Cirque keeps up to half, and is flexible about operations.

The firm is currently running two rigs on Bakken projects in North Dakota, where Cirque and its partners have leased more than 140,000 acres in several discrete project areas. Across its entire position, it plans to drill some half dozen exploratory wells in 2010.

Rob Sterling, above, senior geologist, Cirque resources LP, says the firm is seeking basin-centered oil plays in areas with simple tectonics where it can apply horizontal drilling and hydraulic fracturing.

Among its areas of interest is the central Montana trough, where it holds 110,000 acres prospective for the Mississippian Heath.

“We like the Heath,” says Dea. “It has sourced 100 million barrels of oil into the Tyler sands; it’s got high TOC, it’s very brittle, and we have indications of microfractures. And, it has mixed lithology, like the Bakken.” An additional plus: it’s in the right depth window, which for Cirque is less than 9,000 feet deep.

The company also likes the Niobrara and Mowry, two of the Rockies’ extensive Cretaceous shales. These shales go by an alphabet soup of names, from the Pierre to the Cody, Mancos and more, across the region.

“We actually look at the Rockies as one big basin separated by mountain ranges,” says Sterling. “The rocks don’t vary that much across the system.”

Cirque has confined its Mowry and Niobrara projects to Wyoming, in the Hanna, Big Horn and Powder River basins. The firm prefers not to work in Colorado or Utah, due to what it considers to be onerous regulatory environments in the latter states. “Montana, Wyoming and North Dakota are the states that are best for us to do business in, given our size, our strategy and the barriers to entry,” says Dea.

When Cirque totals up its projects, it is holding acreage that hosts a billion barrels of oil potential. That’s based on unrisked potential at full development.

Its prospective tight-oil shales typically contain between 4.5- to 25 million barrels per section of original oil in place, notes Sterling. Recovery factors in the Bakken at Parshall Field and on the Nesson Anticline may approach 10% at present, but today’s tight-oil plays are more likely to deliver recoveries of 2% to 5%.

But the opportunity to raise those recoveries is very real. “We think recoveries could eventually grow to 10% to 12% with technology already available, such as downspacing,” says Dea. “We see tremendous upside.”

Oil-focused explorer

Denver-based American Oil & Gas Inc. is another independent working the oil-prone shales. It has an enviable position in the Bakken, and has been a pioneer in the Mowry in the Powder River Basin. Now, it has Niobrara possibilities in the Powder as well.

Andy Calerich, president, American Oil and Gas

American just announced strong flows of Niobrara oil from a recompletion on its Fetter project in Converse County, Wyoming. The vertical well, #6-23 Wallis, sits on top of the large Fetter structure. The Wallis flowed 455 barrels of oil and 656,000 cubic feet of gas during a 24-hour test. It is American’s second Niobrara recompletion at Fetter, a 56,000-acre project situated along the southern flank of the basin that it has been working for several years, says Andy Calerich, president.

The company is in the midst of a five-well Niobrara recompletion program at Fetter, and the oil flows are a welcome development.

Initially, American targeted Frontier at Fetter. It planned on commingling Niobrara production with its Frontier gas, and put in removable plugs above the Frontier to perform its Niobrara work. Its first recompletion made some 90 barrels of oil equivalent from the shale. But, given the excellent oil flows from its second recompletion, and the current disparity between oil and gas prices, it now may emphasize the Niobrara as a primary zone.

“Once we have completed the five wells in the Niobrara, we’ll understand better how to move forward on this project,” says Calerich.

American’s latest Niobrara well was treated with some 175,000 pounds of proppant, a larger frac than the first recompletion. “We’ve been learning quite a bit about Niobrara completions,” says Pat O’Brien, chairman and chief executive. The company ran a microseismic survey during the latest fracture treatment, and will apply the results to its three upcoming stimulations.

“We’ll give these wells about six months of flow history,” says O’Brien. “Then we may comingle and develop the Niobrara along with the Frontier formation as a vertical play, which would allow us to hold our acreage for less cost.”

That’s important: competition in the area is heating up, especially since Oklahoma City-based Chesapeake Energy Corp. drilled a horizontal Frontier well on the west flank of the Fetter structure. No results have yet been released on that test.

At Fetter, the Niobrara is 10,500 feet deep and the Frontier occurs some 500 feet below. Both are overpressured, as is the Mowry. That shale, found at 12,500 feet, tested dry gas with no oil in one of American’s deeper wells, so it’s not prospective for oil at Fetter. Interests in the project are held between American, with 69.37%, and North Finn LLC and Red Technology Alliance.

Farther north in Converse and Niobrara counties, American and partners Brigham Exploration Co. and North Finn have been investigating Mowry oil potential at the Krejci project. Additionally, American holds some 13,000 acres in its Conan area, north and east of Krejci, also prospective for Mowry.

In the Krejci neighborhood, the Mowry is 7,500 feet deep, normally pressured and oil-prone. “We’ve been working the Mowry for a long time, and now other companies are moving into the play,” says Calerich. EOG Resources Inc. and Baytex Exploration have Mowry-focused operations to the north of Krejci.

American and its partners drilled five wells at Krejci, and had mixed success. “The Mowry is a very sensitive formation, and we haven’t worked out yet how to stimulate it,” says Calerich. The firm has taken a time-out on its leases. As it has term remaining, it will watch and wait to see how the other operators fare with their Mowry programs.

American Oil and Gas Inc. has grown its Bakken position to 76,000 net acres just west of the nesson Anticline in Williams county, North Dakota, says Pat O'Brien.

Meanwhile, things are happening in the Bakken for the company. American has been working west of the Nesson Anticline in Williams County, North Dakota, for the past five years, and recently the area has been coming into its own.

After some frustrating results, a breakthrough came late last year. Brigham Exploration Co. redrilled a lateral on one of its small Bakken completions in its Rough Rider area, west of American’s position. The recompletion was brought on line at more than 700 barrels a day, and Brigham kicked off a development program. Today, the independent has completed some half-dozen consecutive, high-rate wells at Rough Rider. Its most recent completion, the #1H Strand 16-9, produced at an initial rate of 2,264 barrels of oil equivalent per day.

American’s Goliath area lies smack between Rough Rider and the prolific Nesson Anticline. During the past year, American added substantially to its position, more than doubling its Bakken holdings to its current level of 76,000 net acres. “We’re ready to drill again,” says Calerich. “Our acreage position is compelling, and now we’re going to try to validate it.”

The company is in the final stages of bringing in a partner, and its first well in the revitalized project is slated to spud imminently. A long lateral with 20 frac stages will run between $6- and $6.5 million.

“People have said there are no bad Bakken wells, just bad Bakken completions,” says Calerich. “We’re a good example of that. We were working out here in the early days of the play, before the technology was available to do what we wanted to do. Now it’s time to try again.”

Certainly, that’s the story of the oil-prone shales. The oil has always been present, but it was padlocked in the subsurface. Now, the industry has new technology in its toolkit to attempt to unlock these incredible resources of crude.