The Niobrara Shale is more than a one-trick Denver-Julesburg Basin pony. While current Niobrara headlines extol multiwell pads, extended laterals and rising oil production from multiple benches northeast of Denver, an intriguing but lesser-publicized Niobrara development is underway in western Colorado's Piceance Basin.

In December 2012, WPX Energy Inc., the exploration and production spinoff from midstream pipeline giant The Williams Companies Inc., commenced IP on the GM 701-4 HN1 well from a middle bench in the Niobrara Shale. WPX formally announced the Piceance Niobrara discovery January 22, 2013. It generated an IP rate of 16 million cubic feet per day (MMcf/d) at a flowing pressure of 7,300 pounds per square inch, producing more than 1 Bcf of gas in the first 100 days.

Over the past 17 months, the discovery, originally drilled to 10,200 feet with a 4,300-foot horizontal lateral and 17 fracture stages, has yielded 2.5 Bcf of gas, the most prolific Niobrara Shale well to date. A subsequent 2013 test to the east, in WPX’s Rulison Field, confirmed the deep-lying Niobrara as a dry gas resource play in the Piceance Basin.

For these impressive results, the WPX horizontal well has earned Oil and Gas Investor’s Excellence Award for Best Discovery of 2013.

Sometimes the best thing a company can do is wake up one morning and discover it sits atop the latest geologic treasure trove. WPX holds 180,000 net acres prospective for the Niobrara/Mancos shale beneath its Piceance Basin properties.

“This is where we can make huge money without having to buy a lot of inventory,” said Chad Odegard, Piceance Basin asset team vice president for WPX Energy. “The Niobrara is one of those components.”

WPX will spend about $500 million in the Piceance during 2014, including $75 million to test the Niobrara. Indeed, these are exciting times at the Tulsa-based company. WPX is budgeting $100 million for exploration for the second year running following its spinoff in January 2012. WPX also has acreage in the San Juan and Powder River Basins and the Bakken and Marcellus Shales.

The fact that WPX is nurturing an exploration element in its portfolio speaks to the changes underway as the former pipeline E&P subsidiary develops sea legs in the competitive public independent sector. Rick Muncrief, formerly senior vice president of operations and resource development at Continental Resources Inc., assumed chief executive responsibilities at WPX in May this year. (At press time, WPX sold a 30% working interest in 2,730 Williams Fork gas wells to Legacy Reserves LP, a Midland, Texas-based MLP, for $355 million cash.)

Former corporate parent Williams followed an acquire-and-develop model focusing on efficiencies and resource harvest with zero exploration dollars. Williams originally obtained the Piceance acreage through the $2.8 billion acquisition of Barrett Resources Corp. in May 2001, outbidding multinational major Royal
Dutch Shell to do so.

Williams/WPX has a storied history in the Piceance. In 2004, when “unconventional” was all about tight sands or coalbed methane and no one was discussing shales, the company became the first to implement a broad-based pad drilling program patterned on offshore platforms, featuring up to 22 directional wells from a single site using fit-for-purpose, self-moving rigs. Indeed, the company ordered the first 10 Tier I technology units from Helmerich & Payne IDC, setting off a cycle of fit-for-purpose Tier I newbuild rigs in the domestic drilling sector that lasted until 2008 and saw 350 rigs added to the domestic fleet.

Williams/WPX later ordered four additional fit-for-purpose self-moving Tier I rigs from Nabors Industries Ltd. to develop the Piceance, turning its Mesa Verde holdings into a gas-harvesting factory through simultaneous drilling, completion and production practices—SIMOPs—on pad sites in the environmentally sensitive and topographically challenging area.

At the peak of activity, in 2008, the company employed 27 rigs targeting Williams Forks objectives in the Mesa Verde at 6,000 to 11,000 feet below surface in Grand Valley, Parachute, Rulison and Ryan Gulch Fields. The subsequent collapse in natural gas prices reduced activity in the dry gas basin to less than 10 rigs currently, although pad drilling and batch completions evolved into the standard method to develop unconventional resources across North America.

WPX has drilled more than 4,000 wells in Colorado’s Piceance Basin since 2002, and current dry gas production exceeds 600 million cubic feet per day net. That effort has provided the company with extended infrastructure for gathering lines, water treatment and transportation (100% of the frack water is recycled pro- duced water) and natural gas processing, all of which come into play as the company moves forward with a 10-well 2014 program to delineate the deep Niobrara.

WPX has more than 180,000 net acres prospective for the deep Niobrara Shale. The company drilled four horizontal wells in 2013 and will follow with a planned 10-well, 2014 delineation program beginning on the west side of the company's acreage in Colorado's Piceance Basin.

Scientific reconaissance

The discovery well was preceded by two events. First, farther south, WPX drilled into a time equivalent analog of the Niobrara in the San Juan Basin, tallying a natural gas discovery in 2010. The company followed with a vertical deep test in Colorado’s Grand Valley Field in 2011, obtaining more than 500 feet of core to prospect for deeper objectives under the Mesa Verde gas development.

Following the scientific reconnaissance, WPX determined that the Niobrara’s middle bench offered the best combination of petrophysics and geology for a horizontal test. The well was located in Grand Valley Field partly because WPX possessed a contiguous acreage block of federal lands large enough to host a 4,300-foot horizontal lateral, coupled with a benign downhole environment free from the faulting that characterizes portions of the Piceance.

WPX employed Aztec Drilling Rig 1000, a newly built 1,500 horsepower rig using dedicated natural gas engines and Piceance field gas to drill the Niobrara discovery.

The deep Piceance Niobrara differs from its geologic cousin in the D-J Basin in that it exhibits a high-temperature and high-pressure downhole environment and overlying hard rock formations that make drilling a challenge. WPX looked elsewhere for analogs and adapted completion techniques from the Haynesville Shale for the deep Niobrara, ultimately importing beefier oilfield equipment from South Texas for subsequent Niobrara horizontal work in 2014.

"What we verified in Rulison Field in the far east part of our valley acreage is that the formation exists--same thickness, same petrophysics," said Odegard. "But we also have increased pressure with that depth, which is a large plus, because you gain potential reserves as you go across our valley position."

WPX has not formally discussed EURs for the Niobrara wells, but notes they could perform on a level consistent with wells in the Marcellus dry gas region and the Haynesville.

The 2014 delineation program of up to 10 wells will include two vertical tests. The first will take place as an infill study in Parachute Field, midway between the Grand Valley and Rulison Niobrara tests. The second will be north, in the company’s Ryan Gulch Field, where the Niobrara is deeper than in Grand Valley Field.

The company recently completed a 25,000 acre seismic program and will follow with six to eight horizontal wells, beginning on the west side of WPX’s Piceance acreage in Grand Valley and Parachute Fields. At least one horizontal well will test a second bench in the Niobrara later this year.

WPX recently took delivery and started drilling with a new fit-for-purpose 1,500 horsepower self-moving rig-—part of Nabors Industries' Pace-X rig concept-—to begin the horizontal delineation program.

"We believe we will start drilling 50-day wells immediately with the Nabors rig and, as we repeat our success, we will gain efficiencies,” said Chris Caplis, Niobrara project adviser for WPX. “Our drilling guys are fantastic at cutting days. That’s what they’ve always done in the Mesa Verde."

“We never thought we would see sub-10 day cycle times, but we are there. As we get more comfortable with this rig, as the crews get more comfortable with the rig, 50 days will become 40, then 40 will become 35. We hope to be consistently drilling 30-day wells in the future.”

Science, exploration and the technical aspects of high temperature and high pressure boosted initial Niobrara well costs above $12 million. As horizontal Niobrara delineation moves forward with the new technology rig, WPX is seeking to reduce well costs below $10 million, and 10% to 20% lower yet, when it begins drilling from multiwell pads, many already in existence from its Mesa Verde development program.

The deep-lying Niobrara is just part of the transformation underway at WPX. The company is also developing a nascent oil field in the San Juan Basin of Colorado and New Mexico.

“Exploration ventured out to drill an initial four wells and prove up the concept and viability, and quickly we’ve gone to a development mode out there to bring on the oil production side of our business,” Odegard said.