The Marcellus shale in the northeast US is one of the hottest shale plays in the world. Figures from Pennsylvania’s Department of Environmental Protection indicate that shale gas production increased to 87.8 Bcm (3.1 Tcf) in 2013, a 93.1% increase over 2012 and a 190.3% increase over 2011. At Hart Energy’s recent DUG East event, several presentations focused on this remarkable resource.

Ramping production, dropping rig count

The North American shale revolution has stood many traditional notions about oil and gas development on their heads. The rig count as a leading indicator is one of these notions.

Allen Gilmer, CEO of DrillingInfo, gave the crowd at the event some rather startling numbers. Effectively, since his company began following activity in the Marcellus and Utica shales, production has ramped up considerably. Marcellus gas production saw the beginnings of an uptick in 2010, with daily production rising from about 14 MMcm (500 MMcf) in 1Q to 57 MMcm (2 Bcf) in 4Q. By the end of 2012, daily gas production was four times that amount.

Yet the rig count in the region is dropping. This would seem to be counterintuitive based on traditional thinking, but new changes in the development of unconventional plays paint a different picture.

One of Gilmer’s slides showed a macro view of the movement of rigs in the US. By using GPS tracking, DrillingInfo was able to show where the rigs were moving from and to. “There have been some rigs coming into the Utica and the Marcellus, but a fair number are leaving and going to the Rockies and Oklahoma,” Gilmer said.
A closer view of the region indicates a cluster of movement within and between the two plays, indicating that many rigs are being utilized in multiple areas across the region. “It’s interesting to watch how successful these rigs are,” he said.

The growth of drilling activity in the Utica has somewhat offset a drop of activity in the Marcellus, but the overall rig count has dropped substantially, with little more than 120 rigs running as of October 2013 compared to almost 160 in January 2012. Additionally, more than half of the rigs drilling in the Marcellus shale are drilling outside of Pennsylvania, the original sweet spot.

The most active operator drilling in the region is Antero, followed closely by Chesapeake and trailed by EQT Production, CNX Gas, Cabot Oil & Gas, Gulfport Energy, and Range Resources. Patterson Energy is by far the most active contractor in the region.

Gilmer noted that, unlike some plays like the Eagle Ford where operators stay with the same contractor and often the same crew to increase efficiencies, this is not the case in this region. “Very rarely do you see an operator with a single contractor,” he said. “Typically an operator uses two or three contractors, and contractors work with a lot of operators. That’s good for stability.”

A map of drilling activity in the two shales shows that wells drilled since 2004 are definitely targeting the sweet spots. Gilmer said that the noncore areas should not be overlooked. “My prediction is that in five years, or maybe even two or three years, the areas we think of as noncore are going to have good economic returns because we’re not going to be drilling wells with 6,000-ft [1,829-m] laterals and 2 million-lb fracs,” he said. “We’ve spent a lot of time looking at what we call low-effort results, the idea of 1,000-ft [305-m] laterals and 50,000-lb fracs, looking at what people have done by accident.

“We’re seeing that if you’re in fantastic acreage, it makes sense to put in long laterals. But in areas that are not very good, the benefit you gain by adding more lateral is minimal.”

The average lateral length in the region is around 1,676 m (5,500 ft), he noted.

Well spacing is another issue that continues to generate debate. Gilmer said that while there is not a specific spacing at which production drops to zero, there is a specific spacing level at which the operator will start to recover less gas per well.

“I think the regulatory bodies need to be familiar with this because we’re going to see a steady evolution of drilling more in these noncore areas to extract smaller amounts of hydrocarbons,” he said. “It’s something we’ve seen in every area.”

Of all of the technology and methodology that has caused the rig count to drop, pad drilling is the biggest culprit. Pad-drilled wells have increased from 0% of quarterly rig count total in 2008 to 80% today, Gilmer said. This is particularly prevalent in the southwestern sweet spot, where virtually all of the wells have been pad-drilled from multiwell pads.

“This has made it difficult to understand the rig count,” Gilmer said. “It’s not rig count anymore; it’s how many wells we are drilling.”

It’s also skill and experience. “Given the same geological propensity to produce, the same quality of land, and looking at the difference between the best operators in the play and the average, the best ones will produce 30% to 50% more than the average,” he said. “The worst will produce 30% to 50% less than the average.
“What this really means is that there will be opportunities for people who know what they’re doing to pick up acreage that looks to be bad. People are going to mistakenly take good geological areas that aren’t producing because of bad operating practices and commit the cardinal sin of selling off their acreage because they didn’t drill economic wells.”

Seneca’s success

Most of the Marcellus shale drilling in Pennsylvania has been focused on opposite corners of the commonwealth – the southwest and northeast – but Seneca Resources has plenty happening elsewhere in the Keystone State.

Matthew Cabell, president of the National Fuel Gas Co. unit, told conference attendees his firm continues to complete strong wells across a sprawling acreage block stretching across northern Pennsylvania.

“We’ve taken time to identify sweet spots through the center portion of the state,” Cabell told the group. “We have a significant Marcellus exposure.”

Seneca has substantial acreage focused on the Marcellus totaling 775,000 net acres, “some of which are held in fee so we don’t pay royalty,” he added.

The firm divides its Pennsylvania acreage in two. It has an eastern development area in Tioga, Lycoming, and Potter counties that includes 60,000 net acres, mostly leased. Lycoming County wells have an average initial production rate of 456 Mcm/d (16.1 MMcf/d) and an average estimated ultimate recovery (EUR) of 326 MMcm (11.5 Bcf).

A much larger western area, centered in Cameron, Forest, and Jefferson counties, has about 720,000 net acres, most of which is held in fee. Cabell rated the area “highly prospective” with wells that have had peak seven-day production of 283 Mcm/d (10 MMcf/d) and EURs as high as 244 MMcm (8.6 Bcf).

Acreage of that size covering a prolific trend like the Marcellus means “there is literally decades of drilling for us,” Cabell added, with 1,700 to 2,000 identified derisked locations at US $3 to $4 per MMBtu prices. Things look better still if and when gas prices perk up.

The firm’s fiscal 2013 Appalachia region annual production will exceed 2.8 Bcm (100 Bcf), and Cabell projected fiscal 2014 production will be between 3.5 Bcm and 4 Bcm (125 Bcf and 143 Bcf). Its fiscal 2013 Marcellus exit rate was approximately 10 MMcm/d (360 MMcf/d), and Seneca currently projects its fiscal 2014 exit rate in the Marcellus will rise to around 14 MMcm/d (500 MMcf/d).

Much of that drilling success has come because Seneca has successfully “cracked the code” through an active drilling year, he said. That has yielded a much better understanding of the region’s geology and identified more effective hydraulic fracturing techniques, including longer horizontal laterals and tighter spacing of frac stages.

Seneca projects its fiscal 2014 capital budget for its Appalachian drilling and production operations of $460 million to $520 million, compared with $428 million for fiscal 2013.

Range banks on Pennsylvania

As Range Resources Corp. continues on a “line-of-sight” of 20% to 25% production growth per year, it also benefits from holding some 540,000 net acres in southwest Pennsylvania where three stacked pays come together, combining some of the highest gas-in-place (GIP) estimates in the Marcellus, Utica, and Upper Devonian, according to Range Resources’ president and CEO, Jeff Ventura.

Range holds about 1 million acres prospective for shale in Pennsylvania, where industry’s rapid development of the Marcellus field has taken production to “probably in excess of 12 Bcf/d [340 MMcm/d],” making it the largest gas field in North America, noted Ventura. In addition to 540,000 acres in southwest Pennsylvania, Range holds 315,000 net acres in the northwest, largely held by shallow production, and 145,000 net acres in the northeast, where one rig is expected to hold acreage it plans to develop. However, while Range nominally holds 1 million acres, “1 million acres is really more like 2 million net acres when you look at the prospective stacked pays,” said Ventura. While the company holds 835,000 net acres prospective for the Marcellus, another 580,000 acres are prospective for the deeper Utica, and a further 565,000 acres are prospective for the Upper Devonian, which lies above the Marcellus. Collectively, this adds up to just under 2 million acres.

Ventura noted Range’s proved reserves grew at a compound annual growth rate of 23%, with some 133 Bcm (4.7 Tcf) of resource potential moving into the proved category in the last three years. “That’s really the equivalent of a nice company,” he said.

Regarding Range’s 540,000 net acres in southwest Pennsylvania, “we think our acreage position down there is largely derisked,” said Ventura, citing some 2,100 wells now drilled by industry in the area and up to eight years of production history. Just in the Marcellus, he projected 6,750 potential drilling locations in the area based on 305-m (1,000-ft) spacing (approximately 80-acre spacing). Of these 6,750 locations, only about 500 horizontal wells had been drilled, accounting for a little more that 7% of potential locations and now producing some 16 MMcm/d (570 MMcf/d).

Assuming all the acreage could be drilled at once, all the wells were equal, and grossing up the 16 MMcm/d of current production by 7%, said Ventura, the implied result would be 227 MMcm/d (8 Bcf/d) net.

“We’re not saying that we can get there, but it gives us great confidence that we can get to 3 Bcfe/d to [more than] 4 Bcfe/d [85 MMcm/d to 113 MMcm/d],” said Ventura.

In addition, with three ethane contracts in place, Range has cleared a path that allows the company to produce more than 85 MMcm/d net from the Marcellus alone, said Ventura.

The Marcellus phenomenon

The Marcellus is the undisputed king of North American shale gas plays, and it is expected to retain its heavyweight title for years to come. The experts say tens of thousands more wells are yet to be drilled, and Cabot Oil & Gas Corp. is expected to continue to be a production leader.

Dan Dinges, Cabot’s chairman, president, and CEO, told oil and gas professionals that the “Marcellus is such a phenomenon that it will be hard to duplicate.”

Cabot drilled its first Marcellus wells in Susquehanna County, Pa., in 2006. Since that time, the company has reported several of the best wells in the play. Make no mistake: Cabot’s day in the Marcellus is not done. In fact, Dinges is confident that greater production numbers and favorable results for shareholders lie ahead.

“Right now, Cabot has 3,000-plus identified drilling locations in the sweet spot of the Marcellus. We also have peer-leading rates of return and EUR per lateral foot in the Marcellus. And the Marcellus has 25-plus years of inventory at current production levels,” he said.

And Cabot aims to tap the vast supply of gas by operating around the clock. “We will implement a new rig-move process, and that includes 24-hour operations for rig-up and rig-down,” Dinges said.

Ultimately, Cabot will bank on efficiency as it aims to drill wells in “shorter periods of time and at larger measured depths,” according to Dinges. Also included in the efficiency equation are using CNG to power drilling operations and field gas as an energy source for pumping services, he added.

Dinges pointed out that Cabot has been able to increase the number of frac stages it performs daily. In 2010, the company averaged 2.5 frac stages per day. The daily average is now 5.1, Dinges said, adding that the company record is nine stages per day.

Governor fond of Marcellus

For Pennsylvania Governor Tom Corbett, the benefits of the oil and gas boom in his state can be summed up by a bumper sticker he spied on a pickup truck – “American energy, American jobs.” Except he thinks it should read “Pennsylvania energy, Pennsylvania jobs.”

“I want to be clear about something because there seems to be a question mark about it,” he said. “More than 220,000 jobs have either been created or made more prosperous or more secure by the vast wealth that is being tapped by our own Marcellus and, now, Utica shale plays,” Corbett said.

Corbett spoke to DUG attendees in Pittsburgh, but he was actually addressing the oil and gas industry’s opponents, those he called “economic change deniers.”
“The industry has, to a vast degree, been environmentally responsible,” he said, calling it one of the “inconvenient truths” opponents have had to face.

Corbett challenged drilling opponents and jobs skeptics to visit Pennsylvania for themselves and see the industry’s help in creating jobs.

“Visit Williamsport, the home of the Little League World Series, and see the crowded restaurants, the full hotels, the additional hotels being built, and the stores that sell everything from equipment used on a rig to hats and boots, and then ask the people in those stores if they’re doing this kind of business without the drilling industry,” he said.

Citing the $400 million in impact fees assessed on unconventional wells in the Marcellus during the last two years as a result of statewide legislation called Act 13 and how the funds benefit local economies, the governor said, “If those who question the positive impact you have had from this industry on our communities just took the time to personally visit these areas, they would know what we have learned here in Pennsylvania. Pennsylvania is an energy industry,” he said.

Corbett indirectly attributed some of the jobs creation to Act 13, which was enacted in early 2012.

“We knew that our energy producers would compete not only with other states but with other nations. So we avoided a burdensome and job-killing system of taxation in favor of allowing the industry to flourish, to grow, and to create the jobs and the related business expansion that generates real prosperity and real revenue for all peoples,” he said.

Corbett reminded the oil and gas audience that history is repeating itself in his state by recalling that the nation’s first commercial oil rig, the Drake Well, was drilled in Pennsylvania a little more than 150 years ago. With hydraulic fracturing and horizontal drilling, he said, “Pennsylvania is once again a major energy-producing state, with the world’s most famous natural gas reserve resting beneath us.”

And this time around, he said, the industry has a duty to the environment.

“Under Act 13, we passed the most comprehensive and effective system of guidelines and regulations of any drilling state in the nation,” he said. “Our system protects the many streams and aquifers that we have and, when necessary, (and very rarely has it been necessary), we have imposed fines and taken action to protect the environment. The drilling industry has complied very well with these regulations.”

Counties’ bounty

You only need three reasons to understand why rising US gas production is going to keep natural gas prices low for years to come.

Those reasons are Susquehanna, Greene, and Washington counties in Pennsylvania. Like the real estate mantra that bleats location, location, location as a key to success, these three counties, plus Wyoming and Bradford in northeastern Pennsylvania, are the main drivers in rising onshore natural gas production.

And more is on the way. In fact, the Pennsylvanian Marcellus shale as a whole should peak at 566 MMcm/d (20 Bcf/d) in natural gas production by 2019, roughly double current levels in fewer than six years.

Those three Pennsylvanian counties sit atop sweet spots in the Marcellus shale. Sweet spot drilling accounts for 20% of Pennsylvania’s horizontal wells, according to Cameron Horwitz, director of E&P Research at Houston-based US Capital Advisors. However, Horwitz discovered sweet spot drilling has a disproportionate impact on gas supply after a 2,000-well regional study. Pennsylvanian sweet spots – sort of the Hershey kisses of the Marcellus shale – include one example in which production from just 50 dry gas wells in Susquehanna County is on track to generate EURs of 396 MMcm (14 Bcf) per well.

“These sweet spot areas we’ve identified … will be the driver of (future) US gas supply,” Horwitz said. “Even at $4 gas we have a lot of work to do here, likely over two decades, so it’s just a very bright future to look forward to.”

Susquehanna and Bradford counties alone generate about 80% of the total amount of gas produced daily in the legendary Barnett shale. But those two counties in northeastern Pennsylvania are just one element in a larger theme.

“We see about 200 Tcf [5.7 Tcm] in the Pennsylvania Marcellus shale that is still viable at a $4 gas price or less,” Horwitz said. “That’s about 30,000 remaining drilling locations. If you think about the 85 rigs still running in the play and 1,500 wells drilled each year, that is roughly 20 years left of gas, even if gas prices stay sub-$4 throughout that whole time.”

Take note, conventional gas drillers and dry gas-oriented E&P firms in the Rockies, Midcontinent, and Texas: In Susquehanna County, one Cabot well produced 198 MMcm (7 Bcf) of gas in 13 months. At an average 566 Mcm (20 MMcf/d) for a year, it is the best producing Marcellus well to date. According to Horwitz, Cabot’s Susquehanna County wells are generating EURs that average 368 MMcm (13.8 Bcf) per well, followed by Chief Oil & Gas LLC at 303 MMcm (10.7 Bcf). Decline curves on one Cabot well are on track to produce 1 Bcm (40 Bcf) over the life of the well. On average, a $10 million dry gas well in Susquehanna County produces a 110% internal rate of return (IRR) under present pricing and breaks even at $1.95 gas.

Horwitz defined the Marcellus gas sweet spots as areas that produce an EUR of 227 MMcm (8 Bcf) or greater, with wells economic at $3 gas. Using these criteria, Pennsylvania has two emerging sweet spots at opposite corners of the state. In the dry gas northeastern Pennsylvania sweet spot, Wyoming County leads the way with average EURs north of 311 MMcm (11 Bcf). Most of the activity is in the northern half of the county.

Neighboring Susquehanna County is second with average EURs of 255 MMcm (9 Bcf).

The second sweet spot, in the wet gas area of southwestern Pennsylvania, is led by Greene County, with EURs per well averaging 229 MMcm (8.1 Bcf). Within the Greene County dry gas core, operators have drilled multiple wells that have generated decline curves suggesting EURs of 340 MMcm (12 Bcf), roughly double the “average” Marcellus well. Operators with the best well results in Greene County include Rice Energy, which is generating average EURs of 348 MMcm (12.3 Bcf), and EQT, with a per-well EUR average of 334 MMcm (11.8 Bcf). At a $7 million well cost, Greene County dry gas wells produce an IRR of 95% at $4 gas and break even at $2.05 gas.

The gas play grades into a wet gas zone in neighboring Washington County. Here, wells produce a stream that is 40% liquids before NGL processing. Range is the largest operator in the wet gas zone, though privately held Rice Energy is reporting leading Washington County EURs of 292 MMcm (10.3 Bcf) per well, while EQT is second with an average 258 MMcm (9.1 Bcf). A $7 million Washington County well produces a 77% IRR at $4 gas and an aggregate $40 NGL barrel. The break-even for a well in the wet gas portion of the Marcellus sweet spot is 40 cents.

“Gas is essentially being subsidized by the liquids,” Horwitz said. “Gas is almost insensitive to gas prices in this part of the play.”

Horwitz pegged current production out of the Pennsylvanian Marcellus at 283 MMcm/d (10 Bcf/d).

“Pretty amazing when you consider that three years ago production was less than 1 Bcf/d [28 MMcm/d]. That’s a compound average growth rate of more than 125% each year – pretty incredible,” Horwitz said.

Horwitz’s Pennsylvanian scorecard shows 12,000 horizontal wells permitted and 6,000 horizontal wells drilled during the last six years. Operators were permitting 200 to 300 wells per month at the peak in 2011 to 2012.

“We’ve subsequently seen a slowdown in some of that activity to 100 to 200 wells per month on average, and we’ve seen a pretty significant high-grading as to where that permitting activity is taking place,” Horwitz said. “Counties such as Bradford, Susquehanna, Greene, Lycoming, and Washington have taken a disproportionate share of that activity.”

Marcellus rig count has been range-bound between 80 and 100 wells since August 2012 and is currently slightly above the midpoint in that range. “This will probably hold true for the next couple of years,” Horwitz said.

Also holding true is the rising flow of Marcellus natural gas, an event that has national implications for future domestic gas production and for natural gas pricing.

Airport drilling

Pittsburgh International Airport already serves as a bustling gateway for the busy tri-state area. Now its subsurface will be equally lively. In 2013 Consol Energy leased 8,807 acres of mineral rights beneath the airport from Allegheny County and the Allegheny County Airport Authority, and Consol plans to aggressively develop those rights. “Early indications are the airport offers stacked-play opportunity,” said Nicholas DeIuliis, president, Consol Energy Inc. “We will drill 40 to 45 Marcellus wells on that property.” Upper Devonian potential also exists; that would be additive to the already hefty Marcellus resource base.

Consol figures that the lease bonus, capital expenditures for drilling, and taxes and royalties will amount to a $1 billion project for the county. The operator’s plans call for six well pads, and drilling will begin in mid-2014.

This deal is just one of the strategic thrusts that are reshaping Consol. The venerable firm has been in business since Abraham Lincoln was president, and its longevity is a testament to its willingness to reinvent itself and grasp new opportunities.

Just 10 years ago, Consol was a traditional coal producer. Natural gas was an afterthought, said DeIuliis. Eight years ago, Consol formed CNX Gas to grow its gas business, and three years ago it acquired Dominion Resources’ Appalachian E&P assets. This past October, Consol announced the sale of five of its West Virginia coal mines.

“Today we are an E&P business with a best-in-class legacy coal position,” he said. “There’s no doubt that the change we are seeing is sweeping through our region as well.” Energy from shale represents a once-in-a-generation opportunity to breathe new life into the region’s manufacturing sector. “The Marcellus and Utica gas fields are impacting everything from electric generation to fueling the American manufacturing renaissance to future export opportunities,” he said.

In the Marcellus, Consol currently runs eight rigs with its partner Noble Energy, and it plans to operate at least that many in 2014. Five rigs are at work in West Virginia, and the company expects to have 75 wells drilled by year-end 2013 in the Mountain State.

Consol’s assets also include 300,000 acres that are potentially commercial for the Upper Devonian. It announced a discovery in the Burkett shale that came onstream in June 2013 at 85 Mcm/d (3 MMcf/d) and has exhibited remarkably flat declines in its initial production. Consol also continues to seek bolt-on acreage opportunities that are synergistic, an example of which is the farm-in it recently took on 80,000 Marcellus acres in West Virginia from Dominion Transmission.

The transition to a natural gas producer from a coal producer has been dramatic for Consol. It produced 1.4 Bcm (50 Bcf) in 2005 and doubled that to 2.8 Bcm (100 Bcf) in 2010. Consol estimated 2013 production at 4.8 Bcm (170 Bcf), and it expects to grow those volumes some 30% year-on-year in 2014 and the two years following.

Largely untold is the capital investment that goes with this growth. “If you look at Consol Energy in the next 10 years, nearly $7 billion in capital spend will be dedicated to the Utica and Marcellus plays in Ohio, $7.5 billion to the Marcellus in Pennsylvania, and $14 billion in the Marcellus in West Virginia,” said DeIuliis. “That’s nearly $30 billion pumped into the regional economy in 10 years.”

That’s remarkable vitality for a firm that was founded in 1864 in the depths of the American Civil War.

Permanent, interventionless frac plugs speed production

By Ryan Allen, Baker Hughes

The economics and rapid decline curves of unconventional shale plays make it imperative for operators to start producing from newly drilled wells as soon as possible. The Marcellus shale is serving as an early staging ground for a game-changing technology that has the potential to completely eliminate the coiled-tubing (CT) drillout phase of plug and perf (PNP) completions so that production can be turned on sooner without the risks involved with intervention. Baker Hughes’ SHADOW series frac plugs are permanent millable plugs that are designed to stay downhole and allow operators to produce through the inside diameter (ID) of the plug – without intervention – as soon as fracturing operations are complete.

Improving PNP

PNP technology enables operators to rapidly perforate, stimulate, and produce multistage wells, which explains its dominance as a completion method in unconventional plays. In fact, it is estimated that 70% to 80% of new unconventional oil and gas wells are completed using the PNP method.

Composite plugs, which are designed to set easily and hold the high differential pressures associated with hydraulic fracturing, are commonly used to isolate one newly fractured zone from the next. The primary limitation of the PNP method is that production following the fracturing operation cannot begin until after the isolation plugs have been removed from the wellbore. The plugs and drop balls are drilled out and debris circulated to surface during a live well intervention that usually requires two days but can require three days or longer. Production is delayed throughout the intervention operation.

Operators working in remote locations or, as in the Marcellus, drilling lateral sections that extend beyond the reach of traditional deployment methods have begun requesting alternatives to the composite plug for PNP completions. Baker Hughes responded with the industry’s first interventionless frac plug.

Disintegrating frac balls are key enablers

The new plugs feature a large flow-through ID and use IN-Tallic disintegrating frac balls so production can flow with the plugs in place. The frac balls are made of controlled electrolytic metallic nanoconstructed material, pioneered by Baker Hughes. The frac balls hold pressure during fracturing, then completely disintegrate in the well when exposed to produced fluids to prevent blockages and eliminate debris. IN-Tallic balls are stronger than composite frac balls and can withstand higher pressures without deformation, enabling a larger ID through the plug.

The interventionless plugs are run in-hole and set just like traditional composite plugs. Initial access to the reservoir is created using the company’s Alpha sleeve pressure-actuated valve rather than a CT-deployed perforating gun. Zones can be independently treated after dropping a ball to seal off the plug. Multiple plugs can be run to isolate multiple zones, and more stages can be fractured at higher pressures. And commingled testing and production of zones both above and below the plug can occur once a higher pressure differential from below is established. Because the plugs can be set in horizontal sections beyond the reach of CT-conveyed milling tools, longer lateral sections can be fractured to expose more of the reservoir to the wellbore.

Field trials for the plugs began in May 2013, and uptake has been quick. The company recently deployed the plugs during a PNP application for an operator in the Northeast who was trying to cut down its completion time. The customer ran 14 units and saved approximately two days of time on location that would have otherwise been spent performing drillouts. For this operator, the plugs eliminated the need for a CT unit and accelerated the startup of production.

Comments