DALLAS—Good potential awaits the industry in several prospective plays, even after the shale gale identified vast new reserves in the Permian, Marcellus and elsewhere. That’s what Peggy Williams, editorial director of Hart Energy and a certified petroleum geologist, told a Petroleum Engineers’ Club of Dallas luncheon April 21.  

Her presentation on emerging plays identified three highly prospective regions. Two old plays that lend themselves to new drilling and completion technology are the Powder River Basin in Wyoming and Montana and the Permian Basin’s San Andres Formation. A new—and relatively unexplored—shale play is in Mexico’s Tampico-Misantla Basin.

“Well, that’s almost in the U.S.,” Williams added with a chuckle, noting that although it is not, the basin is nearby, and Mexico’s recent constitutional change opens the Tampico-Misantla play to U.S. and other foreign firms.

Cretaceous In The Powder River Basin
The Cretaceous section in the Powder River Basin is hardly a new play, Williams noted, with production from the basin dating from the 1880s. It was the scene of the infamous Teapot Dome scandal of President Warren Harding’s administration.

In the past 180 days, with more than 1,800 horizontal drilling permits issued, “things have been quite lively here,” she said. “It brings an analogy to the Permian Basin with multiple, stacked plays. The Powder River Basin reservoirs are primarily oil-prone with associated gas, with the exception of the shallow coalbed methane play.”

The bulk of recent activity has been centered in Wyoming’s Converse and Campbell counties. The most popular target has been the Niobrara, with producers also planning wells to tap seven other zones, including Turner, Frontier, Parkman and others. The reason for the excitement is the ability to stack multiple objectives within a 4,800-ft prospective section, and to obtain excellent flow rates via horizontal drilling and multi-stage fracturing in those reservoirs.  

Units of Anadarko Petroleum Corp. (NYSE: APC) and Anschutz Exploration Corp. have been granted the most permits in the past six months. The Wyoming office of the U.S. Bureau of Land Management held a February lease sale that attracted $129 million in bonuses—the highest amount of revenue and most acreage sold (183,000 acres) in the past four years.

The sale’s top per-acre bid, $16,500, came from Peak Powder River Resources LLC for a 317-acre lease in southwestern Campbell County. “That’s huge for a Rockies play,” Williams observed.

Devon Energy Corp. (NYSE: DVN) is among producers active in the Powder River. It said in a recent presentation that it projects drilling and completion costs to range from $6 million to $7.5 million per well for the Parkman, Turner and Teapot objectives. Average EURs will range between 500,000 barrels of oil equivalent (Mboe) and 900 Mboe per well.

San Andres In The Permian

To the south, the Permian’s San Andres “is hardly new,” much like the Powder River, she said. Of the 30 Bbbl of oil produced in the Permian in the past 90 years, some 12 Bbbl flowed from San Andres zones, along with some 2 trillion cubic feet of natural gas. The San Andres is a Permian-age carbonate reservoir that produces across much of the Permian Basin.

The current Permian gold rush features more than 140 horizontal San Andres permits granted in the past 180 days, Williams added. Yoakum and Cochran counties, Texas, have seen the most activity, but other wells are proposed as far south as Pecos County, Texas, and to the west in New Mexico’s Lea, Roosevelt and Eddy counties.

Ring Energy Inc. (NYSE MKT: REI) has been the most active E&P, filing 25 of those permits.

Williams said what makes the San Andres different now is that horizontal wells target the formation’s transition zones below established oil/water contacts. The transition zones extend below what was traditionally considered to be the oil/water contact and also extend laterally past traditional field boundaries. The horizontal legs typically produce a great deal of water, and oil cuts tend to rise as reservoir pressures are reduced.

Water production can be significant with the accompanying disposal issues. However, “there is an immense amount of oil there,” she added.

The San Andres horizontal targets lie at vertical depths between 4,500 ft and 5,500 ft. The new-era San Andres wells cost between $2 million and $2.5 million, according to Monadnock Resources, which has been active in the San Andres. The company said in a recent presentation that San Andres EURs are 300 Mboe to 450 Mboe. Fracking programs continue to evolve, with current designs featuring 12 to 16 stages on 1-mile laterals using 600,000 to 1.5 million pounds of proppant, it said.

Alternatively, a lower, residual zone lends itself to development using methods such as CO2 flooding that were created for tertiary recovery. Kinder Morgan Inc. (NYSE: KMI) is pursuing a horizontal San Andres project targeting the residual oil zone at its Tall Cotton project in Gaines County, Texas.

Upper Jurassic Mexican Shales

Unlike the well-established plays described by Williams, Mexico’s Upper Jurassic shales in the Tampico-Misantla Basin along the Gulf Coast are a newcomer.

Pemex discovered Amatitlán Field in 1962 and production peaked in 2005 at a modest 650 bbl/d from conventional Chicontepec reservoirs. Interest is now shifting to promising shale formations deeper in the section. The Pimienta, Taman and Santiago shale objectives look to be a very tempting target. “They stack up well with other shale plays already developed in the U.S.,” she said.

Texas’ Cretaceous Eagle Ford is a good analogy for reservoir quality, with similar metrics for total organic carbon content, porosity and permeability. Geochemical analyses predict that the Mexican shale formations will also be able to produce light grades of oil. And, at 500 ft to 1,000 ft thick, the Pimienta, Taman and Santiago shales are up to 4xthicker than the Eagle Ford. 

Russia’s Lukoil and Canada’s Renaissance Oil Corp. plan to spend $60 million to develop the 56,800-acre Amatitlán Block. The companies will target revitalization of the conventional producing zones along with exploration of the Upper Jurassic shales. If the program comes together as planned, their effort will be among the first foreign-operated unconventional developments in Mexico.

Many challenges remain, of course. Despite Mexico’s legal reforms, development terms remain to be settled, Williams said. The Amatitlán Block is currently under a service contract with Pemex that should migrate soon to an E&P license, but “timing is not certain,” she added. Taxes and royalties need to be worked out, and unconventional drilling in Mexico is in its infancy, “so early wells may carry high well costs.”

Other issues will be developing the basin’s supply chain, dealing with local communities and pending operating rules. And as for all non-Mexican energy firms looking to enter the country, next year’s Mexican elections and varying oil prices are “wild cards” that are yet to be settled.

Paul Hart can be reached at pdhart@hartenergy.com.