ECA Highlighted in The American Oil & Gas Reporter's IOGA Article
Marcellus Shale Moves Toward Maturity
The American Oil & Gas Reporter
March 2010
By Bill Campbell
CHARLESTON, W.V.–Everybody loves babies; they generate intense interest and great expectations. But it is when a baby begins to grow and reveal his personality that the excitement really begins.
By that analogy, it was easy to understand the Marcellus Shale “buzz” that filled the Marriott Town Center Hotel in downtown Charleston for the Independent Oil & Gas Association of West Virginia’s winter meeting, Jan. 26-27, reflected luncheon keynoter Gregory R. Wrightstone, director of geology for Texas Keystone Inc.
“When I talked with you last year,” Wrightstone recalled, “I said the play was in its infancy. In only a year, that infant has grown to be a young man. It is not yet quite mature, but it will be before long.”
Wrightstone and representatives from a trio of companies active in the play offered some perspectives on the opportunities and challenges presented by the Marcellus Shale. But as with humans, a fifth speaker remarked, good and bad intermingle in almost every action. “The Marcellus is a very, very big deal. It is a large play and it is going to be here for a long time,” said E. Russell “Rusty” Braziel, managing director of BENTEK Energy Inc. in Evergreen, Co. “It is going to change the flow of natural gas around the country, and that makes a lot of people afraid of it.”
Marcellus Excitement
To illustrate the pace of quickening Marcellus excitement, Wrightstone noted that the number of Marcellus Shale drilling permits issued in Pennsylvania nearly doubled between second and third quarter 2009, and tripled from fourth quarter 2008. As of November, he reported, there were 1,415 Marcellus drilling permits issued but not drilled in Pennsylvania, while 708 wells had been drilled.
By comparison, he added, West Virginia reported 1,357 Marcellus completions as of November and 1,000 permitted but undrilled wells, although he pointed out that only 124 of those West Virginia completions had come in the high-pressure region that was yielding reserve reports in excess of 1.0 billion cubic feet a well.
With the “latest and best” estimates putting the Marcellus’ recoverable reserves at 300 trillion-500 trillion cubic feet, Wrightstone said that made it the world’s second largest natural gas field, behind only Iran’s South Pars North Field, which holds an estimated 1,400 Tcf. But the Marcellus likely is more than double the size of Russia’s Urengoy Field, which holds 222 Tcf, Wrightstone continued, while the largest conventional gas field in the United States is the Hugoton at 81 Tcf.
He added that the Appalachian Basin had produced 42 Tcf of gas throughout its history, while its largest structurally controlled Oriskany field, the Driftwood-Bennezette, had produced 260 Bcf. “Range Resources essentially is discovering a new Driftwood-Bennezette Field every two and a half months,” Wrightstone commented.
Tim Dugan, central and south district manager for Chesapeake Energy, said the Marcellus spanned 15 million acres, which was five times the areal extent of the Haynesville Shale and 10 times that of the Barnett Shale. “The Barnett covers 5,000 square miles,” Dugan added. “Just the 20 percent of the Marcellus Shale that is in West Virginia is four times bigger than the Barnett.”
Developing The Marcellus
Chesapeake obtained a leading position in the Marcellus through its 2005 acquisition of Columbia Natural Resources, Dugan reported. He said the company drilled its first horizontal Marcellus well in August 2007, and was running 15 rigs at the end of 2009. Chesapeake anticipates putting 35 rigs to work in the Marcellus this year, Dugan continued, on its way to high of 40 rigs in 2011.
Dugan said Chesapeake was averaging initial production rates of 3.5 million cubic feet a day through 30 days on its Marcellus horizontals, with estimated ultimate recoveries of 4.2 Bcf. “Our budgeted drilling cost is $4.5 million a well,” he revealed. “That gives us a finding and drilling cost of $1.28 an Mcf.”
Chesapeake’s goal, Dugan added, is to reduce drilling and completion costs to $3.5 million. Already, he said, it has lowered drilling-cycle times from 40 days to about 20.
Denny Mills, senior engineer with Petroleum Development Corp. in Bridgeport, W.V., emphasized PDC’s scientific approach to developing the Marcellus. Noting the company had completed one 10-square-mile 3-D shoot in West Virginia and was working on a second, he said, “We want to use 3-D seismic to select locations. We use a logging suite for structure and rock mechanics. Our stimulations are put together with simulators using log data. We use tracers to track sand after the fracs and verify our models, and we plan to use microseismic for fracture mapping our horizontal wells to track height growth.”
Kyle Mork, vice president of eastern operations for Charleston-based Energy Corporation of America, seconded the importance of 3-D seismic. “We think it is going to be critical for most areas,” he said. “Even in areas that are fairly quiet, structurally, we are finding enough structure that it is very difficult to stay in section if you try to drill a 3,000-4,000 foot lateral without seismic.”
Although Mork said ECA tested the Marcellus through a Department of Energy-sponsored project in the late 1970s, “we really got busy in 2005.” Over the past couple years, he said ECA had transitioned from drilling more than 100 traditional Appalachian vertical wells each year to around 20 horizontal wells. “We have gone very quickly to pad drilling. We find that saves significant dollars, although it certainly adds some new challenges as well.”
Although he held that pad drilling would be a key to developing the Marcellus, Mork acknowledged the logistical challenges of moving in equipment and supplies to complete multiple wells at one time “go up exponentially.”
Operation Procedures
Mork reported that ECA was drilling horizontal Marcellus wells on 80-90 acre spacing with 1,000 feet between laterals, “but we really think that is going to come down.”
A question Mork said ECA was asking involves fracture flow back. He said that whereas vertical Marcellus wells generally recovered 50 percent of frac fluids, “we are seeing more like 10-15 percent on the horizontals. Where does that water go? Would we be better off getting it back? Does it hurt ultimate recovery?”
Dugan cited water management as one of the greatest challenges facing the Marcellus industry. Estimating an average 4,500-foot Marcellus lateral required 4.5 million-5.0 million gallons of water to frac, he said Chesapeake’s goal was to achieve zero discharge of all produced, drilling and fracture flow-back water by the end of 2010 in order to eliminate disposal and water hauling, and reduce costs.
He said Chesapeake piped the majority of its water to location in order to reduce truck traffic. He said the company had built 26 interconnected impoundments that held 3.0 million gallons of freshwater, and planned to build 18 more this year.
Likewise, Mills said Petroleum Development Corp. was trying to use all its water, including that from its small, Upper Devonian Sand recompletion projects. “We don’t dig pits anymore,” he advised. “We capture our flow back in tanks so we don’t disturb the ground any more than we have to.”
Dugan emphasized Chesapeake’s best management practices, including employing the Reasonable and Prudent Practices for Stabilization procedures developed by the American Petroleum Institute and the Independent Petroleum Association of America for erosion and sediment control. “We build a berm around the external edge of our locations,” Dugan went on. “We use secondary containment within our locations to control spills. We have sumps to collect anything that may get outside of that secondary containment.”
In its efforts to build good community relations, he said, Chesapeake has hired a traffic coordinator to prevent traffic jams on the narrow, winding roads that mark much of rural Appalachia. “We are escorting all our permitted truckloads to and from locations in groups of three, and we pilot school buses in and out every day,” Dugan said.
Changing Price Differentials
Historically, BENTEK’s Braziel reminded IOGA WV, natural gas prices in the West generally have been less than Henry Hub, while prices in the East have exceeded the Henry Hub price.
But in the past couple years, he said, completion of the Rockies Express Pipeline along with five major Southwestern and Mid-Continent projects–Texas Gas Transmission, and Mid-Continent Express, Gulf Crossing, Gulf South, and Southeast Supply Header pipelines–have added 6.4 Bcf/d of pipeline capacity flowing into the eastern half of the United States.
To illustrate the impact on traditional natural gas price differentials, Braziel noted that the average Henry Hub price for 2007 was $6.94 an Mcf, while the average price in the Rocky Mountains was $2.90 an Mcf less, and prices in Appalachia and farther northeast exceeded Henry Hub by $0.27 and $1.49, respectively. But in 2009, he said, negative basis in the Rockies dropped to only $0.19 on average, while Appalachia and the Northeast saw their positive differentials contract by $0.16 and $1.16, respectively.
“Flows and changes in supply and demand relationships change basis,” Braziel remarked. “Keep that in mind because there are more changes coming to a market near you.”
One major change, he allowed, is the potential of the Marcellus Shale to add to natural gas supply in the eastern United States. Braziel said BENTEK’s analytics group projected Pennsylvania’s 1.0 Bcf/d of Marcellus production likely would increase to 2.0 Bcf/d by 2015, and could reach as high as 5 Bcf/d-6 Bcf/d if political and infrastructure constraints could be resolved.
To examine the impact of increasing Marcellus production, Braziel compared Appalachian gas supplies to a bucket. “During summer 2009, we put 1.4 Bcf/d of Canadian gas into that bucket,” he reported. “We put in 1.6 Bcf/d of Mid-Continent and Rockies gas. We added 5.3 Bcf/d from the Gulf of Mexico region, and local production was 2.2 Bcf/d.”
Of that total 10.5 Bcf/d of natural gas supply, Braziel said, 3.2 Bcf/d was consumed locally, 3.7 Bcf/d went east to Philadelphia, New York and Boston markets, and the remainder went into storage. “The question then is what happens when that 2.2 Bcf/d of Appalachian production gets a lot bigger?” he posed.
With minimal increases in demand expected in the near future, Braziel predicted the first 1 Bcf/d of additional Marcellus volumes would “steal market share from Canada.” A 2 Bcf/d increase in Marcellus gas would begin to back out supplies from the Mid-Continent, Rockies and Gulf of Mexico, he said.
“But that is not all that is going on,” Braziel continued, pointing to predictions that imports of liquefied natural gas into the U.S. East Coast were likely to grow as well. LNG will displace Appalachian gas that had been flowing to Eastern markets, likely backing out even more Gulf of Mexico supplies, he projected.
What it all means, Braziel concluded, is “Appalachian gas prices are going to continue to be under pressure. The more gas that has to move out of (Appalachia) to places besides the East means the basis advantage this area has seen for a long time could go away.
“We could have a lot less gas coming in from the Mid-Continent and the Gulf,” Braziel said. “And if that happens, the value of pipeline capacity into this area has to decrease and the value of pipeline capacity out of this area has to increase.”
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