Research on Marcellus shale drilling now underway in Monongalia County

From an Article by Luke Torrance, Pittsburgh Business Times, December 24, 2018

Testing is set to begin this week in West Virginia as part of an effort to advance hydraulic fracturing techniques that would allow the extraction of natural gas to be done more efficiently.

The drilling tests are being carried out by the Marcellus Shale Engineering and Environmental Laboratory (MSEEL), a research partnership between West Virginia University, Northeast Natural Energy, and the U.S. Department of Energy’s National Energy Technology Laboratory (NETL).

The tests will seek to improve gas recovery from horizontal drilling and hydraulic fracturing, a method in which rock is fractured by pressurized liquid, releasing the natural gas. They will be carried out near Core, W.Va., which is located about 15 miles northwest of Morgantown.

Previous research by WVU and Northeast Natural Energy led to the creation of stimulation zones that offered the best well sites around natural fractures in the shale. These sites were monitored using seismic and fiber optic distributed temperature and acoustic sensing, a method that is too costly to be used on all wells.

“Therefore, aided by advanced numerical modeling developed by WVU, the project team will compare the use and results of new completion/stimulation techniques at the Core site to the large array of relatively cost-prohibitive techniques used in the Morgantown Industrial Park wells,” according to NETL.

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Man dies from injuries sustained in explosion at MarkWest facility in Washington County, PA

From an Article by Luke Torrance, Pittsburgh Business Times, December 20, 2018

A man who was critically injured in an explosion at the MarkWest facility in Washington County, PA, last week has died, according to the Allegheny County Medical Examiner.

Jeffrey Fisher, 61, of Salem, W.Va., was one of four workers injured last week after an incident near two temporary tanks that were on-site for routine maintenance led to an explosion on December 13th. The men were working at the MarkWest facility in Houston, Pa., which is owned by Marathon Petroleum.

Southwestern Energy paid $5 billion for Marcellus & Utica holdings from Chesapeake Energy in December of 2014

Times are tough financially for frackers (and not very good for the rest of us either).

Essay by S. Tom Bond, Retired Chemistry Professor & Resident Farmer, Lewis County, WV

Seeking Alpha, an investment newsletter, carried an article called “Natural Gas: Death By One Thousand Paper Cuts… Then A Huge Axe Wound.” That author was thinking about the problems of investors who speculate on natural gas, trying to buy low and sell high. For them it has been coming out the other way around, buying high and selling low, all last year, but especially in the fall. The article was written at the end of October, when gas was at $2.281 per mmbtu. It had been $3 in May. Marcellus Gas.org gives November cloud sourced prices to royalty owners of $1.73/Mcf. (The Mcf in this case having slightly more energy than the mmbtu unit.)

The real hit though is being felt by the over-extended companies that find and produce natural gas. The case of Chesapeake is familiar, the flamboyant Aubry McClendon, who started the company got it seriously in trouble and they eventually kicked him out. The new CEO has said more than half of the deals Chesapeake had when he arrived were clear losers. They are still in trouble. Chesapeake stock lost 22% in 2014 and the CEO compensation was $14.7 million, earning it the position of 25th in Yahoo finance list of worse-performing CEO’s for that year.

That list is interesting. Looking further at it, Nabors, a company that actually does the drilling, made it at 24th; Weatherford at 19th, Kosmos 17th; Continental Resources, 14th; Southwestern (which bought Chesapeake’s old office in Jane Lew, my Post Office town), 13th at a 30% price decrease; Range Resources, 10th, with a loss of 35% in stock value; WPX, a big fracker at 8th; Whiting Petroleum Corporation, 6th; Cobalt International Energy, 4th, Ensco PLC (an offshore company), 3rd with a 47% loss; and in first place, Linn Energy, with a drop of 67% in 2014. Then an 80 % drop in 2015. Linn CEO compensation was $10 million in 2014!

“Energy companies” were the worst performing sector of the S&P. Real Money, an investment site, recently had an article “Balance Sheet Worries Spell Doom for These 4 Energy Names.”

The first on the Real Money list was – Chesapeake! It was the worst performing stock in the S&P 500 in 2015. (List above was for 2014.) As of the third quarter, Chesapeake Energy has $3.6 billion in current assets but it has $4.6 billion in current liabilities.

Second on the list was Southwestern, also mentioned above. The article says, “This Texas-based company proved that one company’s trash is another company’s, well, trash. Late in 2014, Southwestern Energy acquired Chesapeake Energy’s wells in the Marcellus and Utica shales.” The stock fell 74% in 2015. “As of third-quarter earnings, the company has $570 million in current assets to cover $782 million in near-term liabilities. While the company does not have any debt coming due in 2016, it does have a hefty debt load coming due in 2018, which includes two notes that total $950 million and a term loan the company announced in November for $750 million.

Ultra Petroleum is third, its shares fell 82% in 2015.

Fourth is Consol Energy. It bought the exploration and production business of Dominion Resources in 2010 (including drilling rights under the Lost Creek Storage Field, where my surface lies). The article states, “Fortunately, the company does not have any significant debt obligations coming due until 2022. However, Consol Energy has $970 million in current assets to cover $1.9 billion in short-term liabilities, as of the third quarter. Shares of the company were down 77% in 2015.”

As I mentioned in a previous article, somewhere in the high 30′s of exploration and production companies (out of a total of somewhere in the 50′s ) have taken out Chapter 11 bankruptcy. This allows reorganization. Chapter 7  (liquidation) bankruptcy causes the company to disperse its holdings to creditors and that  is the end of it.

Public opinion is slowly coming around, too. According to Leslie Stahl in 60 minutes, “Taking short cuts and human error are endemic to this industry.” “Natural gas has been the ugly step child of the national energy debate, never getting the political muscle of coal or oil.” Except in West Virginia, of course.

The fracking industry doesn’t want federal regulation. You’d think dealing with one set of rules for all states would make it far easier for them. But the federal government is capable of research and is somewhat less subject to direct political influence. It is easy to get the puff pieces that influence people who never see fracking from legislators and their support for favorable legislation. Some of it is pretty obvious. Recently a legislator published a favorable article, and subsequently a permit was published for a well on his property.

Another problem for frackers is the regular appearance of new research that contradicts their pretense that “fracking never hurt anyone.” Research on health hazards, property value declines, public water contamination, and other nuisances has been coming out for years.

Some recent health research titles are: “Fracking plays active role in generating toxic metal wastewater, study finds,” “Fracking’ Linked to Low Birth Weight Babies,” and “New study connects fracking with lower sperm count.” Some are quite ominous: “Malignant human cell transformation of Marcellus Shale gas drilling flow back water.”

The recent connection between fracking and earthquakes is very bad publicity, since these people have a clear claim to monetary damages. The huge waste of gas by the fracking industry is under attack. The Porter Ranch leak going on for months in California is bad news for the industry. It is comparable to the Deepwater Horizon spill in the Gulf of Mexico. The article “Why are Range Resources executives selling their stock?” created considerable interest. “Texas Fracking Zone Emits 90% More Methane Then EPA Estimated” ties government complicity to corporate interest, as did the Public Herald’s report finding that the Pennsylvania DEP fracking complaint investigations are “Cooked & Shredded.” All the articles about divestment of oil and gas stocks by large owners must have hurt also.

Times are tough, fellows. When your costs for removing fracked oil and gas are $20 to $40 more per barrel or barrel-of-oil-energy-equivalent, you face serious competition from the Saudis, Russians (who have five and a half times as much gas, all conventional gas. compared to all the U. S. reserves, including fracked gas) and others overseas. That $20 to $40 difference doesn’t count the damage you do in the fracking fields, either. When the general public catches on to this, it is going to be worse, too. With the cost of wind energy decreasing by 60% in the last six or seven years and the unlimited sun power being captured with greater and greater efficiency, it’s going to be real tough. Fellows, your political activities are not enough to overcome your cost disadvantages now in the near term.  So what will the future hold?

Utica gas production (bright line) increasing

`Monster’ Gas Wells in the Shale Patch Still Flowing at $2.00 per Thousand Cubic Feet

From an Article by Jonathan Crawford, Bloomberg News, November 6, 2015

>> Utica’s share of the natural gas supply in the northeastern US may double in five years

>> Prolific Utica and Marcellus wells paying off even as natural gas prices slump

Prolific natural gas wells in the Utica region are helping drillers in the eastern U.S. survive the worst price collapse in three years.

While producers are choking back gas flows across the U.S., explorers in the Utica are cutting costs and boosting output to increase profits. EQT Corp.’s return from one of the “monster wells” there may reach 47 percent, four times the average in the neighboring Marcellus Shale, according to consultant Bentek Energy LLC.

Output in the Utica, which stretches from Ohio to New York, is “becoming more economic, even in an environment when it’s $2 gas,” said Luke Jackson, an analyst for Denver, Colorado-based Bentek Energy LLC.

U.S. gas suppliers have become more resilient in response to sinking prices that are on pace to average the least this year since 1999. The added production from the Utica threatens to prolong a nationwide glut of the power-plant fuel and keep prices low. Production there may continue to gain at a gas price as low as $1.69 per million British thermal units, according to Bloomberg New Energy Finance.

Magnitude of Utica Well Production

“We’re probably seeing the worst-case scenario right now and these wells are still producing a lot of gas and are still economic to develop,” Maria Cortez, a Houston-based research analyst at Wood Mackenzie Ltd., said by phone Wednesday. “The sheer size of them really outweighs any negative impact from the pricing.”

Natural gas for December delivery rose 1.1 cents to $2.375 per million British thermal units at 12:58 p.m. on the New York Mercantile Exchange. Futures have slipped 12 percent in the past two months.

Rigs targeting gas in the Utica climbed to a six-month high last week. Those in the Marcellus have meanwhile fallen almost 40 percent since April, Baker Hughes Inc. data show. Gas output from a new well in the Utica will surge to 6.15 million cubic feet a day in November, topping all basins except the Marcellus, U.S. government data show.

Utica gas output continues to climb as production in the Marcellus shrinks, as seen in the graph above.

EQT is putting expansion on hold in parts of the Marcellus to home in on drilling in the Utica, planning 10 to 15 wells there next year, Chief Executive Officer David Porges said in a call with investors in October. The Utica formation “could be larger than the Marcellus over time,” he said.

“We are encouraged by the early results from our well and others in the Utica and will know even more as we continue testing throughout the rest of the year and into 2016,” David Schlosser, the company’s executive vice president of engineering geology and planning, said in an e-mailed statement Friday. “The Utica certainly has the potential to be more economic than the Marcellus, but it’s too early to make a definitive call.”

Doubling Share as Utica Output Matches Marcellus

Cortez said the Utica’s share of gas production in the Northeast US may double in the next five years and eventually match the output of the Marcellus as costs shrink. Production at an EQT well in the Utica reached an initial rate of 73 million cubic feet, a level of output unheard of in the rival Marcellus basin, Cortez said.

“It was the Marcellus for a long time, 2011, 2012, 2013 — now, I think increasingly more folks are talking about the Utica,” Jackson said at the Platts 17th Annual Financing U.S. Power conference in New York last week. “This is really why we think gas prices will be lower for longer, is because we have so much production coming out of this northeast region.”

Sharp declines in well production typical in Ohio’s Utica Shale

From an Article by Bob Downing and Doug Livingston, Akron Beacon Journal, January 3, 2015

In the world of shale gas in Ohio, the top-producing wells aren’t king of the hill for long. Take the Tippens 6HS well, for example.

Located in Monroe County in southeastern Ohio, it produced more natural gas in the first quarter of 2014 than any other Utica Shale well in the state — some 1.117 billion cubic feet of the resource in 80 days, according to Ohio Department of Natural Resources records. That’s enough natural gas to fuel 12,000 houses for a year.

But the well that gushed 13,972 thousand cubic feet of natural gas per day in the first three months of 2014 saw daily production drop 41 percent in the second quarter to 8,180 thousand cubic feet per day and another 26 percent in the third quarter to 6,015 thousand cubic feet per day.

By autumn, the Tippens well was producing less than half the natural gas that it had during its peak output and slipped from No. 1 to No. 72. It went from being a stellar Ohio well to a good-producing well.

Similar drops are showing up in nearly all of Ohio’s horizontally drilled natural gas wells. Such numbers are evidence of what drillers call “production decline curves” — drop-offs over time. It’s a common (and expected) occurrence for shale wells, even in wells expected to produce for 30 years or more.

The bottom line: Shale wells produce the most in the first few years or, as evidenced in the sharply declining production rates in Ohio, their first few months. Understanding decline curves in the Utica Shale is an important and useful tool in decision-making for drilling companies. Sharp drops mean less money for drillers and less in royalty payments for landowners as wells age. Simply put, a decline curve is a graph of crude oil or natural gas production over time. As the products are extracted, production volumes trend downward. Hence, the term decline curve.

Analysis of Ohio’s decline curves is more complex. It won’t be possible to gauge fully how the Utica Shale in eastern Ohio compares with other shale formation in the United States until more time has passed and the Ohio Department of Natural Resources collects more data. Only five quarterly reports are now available.

Analysis of output

An analysis of Utica wells tapped in each of the first four quarters — from July 2013 through June 2014 — shows natural gas production had dropped 65 percent, said Dr. Jeffrey C. Dick, a professor and chair of the department of geology and environmental sciences at Youngstown State University and an expert on Utica Shale.

He estimated that Utica Shale production will drop 33 percent in the second year of a well’s life and another 22 percent in the third year. Decline is projected at another 17 percent in the fourth year, followed by 13 percent and 11 percent in the next two years, he said in a review that has circulated widely.

A graph of the annual declines resembles a swimming pool slide — unmistakably steep at first then gradually leveling off. Still, that initial Utica Shale production decline for the first year is “not too bad,” Dick said.

The Utica Shale production curve “is less of a drop than you might expect,” he said. It might “sound terrible, but it’s a pretty good number, actually.” Some production curves are as high as 80 percent in the first year, so what the Utica Shale is showing is “a fairly typical curve,” he said. Production drops of 80 percent have been found in the Haynesville Shale in Arkansas, Louisiana and Texas; parts of the Eagle Ford Shale in Texas; the Bakken Shale in North Dakota; and the Marcellus Shale in Pennsylvania, Dick said.

Determining decline rates is not easy, he said, because drilling companies have different approaches to production. Some want to draw down wells quickly, while others might restrict production to extend the lives of the wells or to wait until low prices rebound. Dick said that often the key for drillers who want to keep production totals high is for them to drill additional wells when production starts to decline significantly.

Important question

Drilling a Utica Shale well can cost from $6 million to $10 million, however, and an important question becomes: Can companies afford to keep drilling such wells?

Wells also can be hydraulically fractured, or fracked, multiple times to boost production. Even with the sharp decline curves, Ohio is not experiencing drops in total oil or natural gas production because additional wells are going online each quarter.

To date, Ohio has approved 1,735 Utica wells, of which 1,277 have been drilled. A total of 707 Utica wells are producing, according to ODNR figures. The most recent report, from third quarter 2014, for 717 wells showed total oil production of 3.013 million barrels and 132 billion cubic feet of natural gas. Both totals were significant jumps from the second quarter, when 504 wells were listed.

See also:  www.FrackCheckWV.net

Gas Leasing Still Hot in Upper Ohio Valley

From Article By Casey Junkins, Wheeling Intelligencer, November 11, 2013
         
North, south, east and west, natural gas abstractors continue flooding courthouses throughout the Upper Ohio Valley in the effort to lock up land for Utica and Marcellus shale drilling.

A trip to the Belmont County Recorder’s Office last week found at least 25 abstractors inside the office, with some even working upstairs on the mezzanine level. Though hectic, the activity seems orderly.

The rush continues due to the impressive amounts of oil, natural gas and natural gas liquids that companies such as Chesapeake Energy, Chevron, Gulfport Energy, Antero Resources, Magnum Hunter, Hess Corp. and others are pumping throughout the area.

A common sight at Belmont County, Recorder Mary Catherine Nixon’s office these days, as natural gas abstractors crowd in to dig through property records to see who owns certain oil and gas rights.

Tim Carr, the Marshall Miller Professor of Energy at West Virginia University, estimated that one Barnesville area Gulfport well could have been producing about $100,000 worth of revenue per day earlier this year. Gulfport also has the “monster” – as labeled by energy investment firm Global Hunter Securities – Shugert well that yielded as much as 28.5 million cubic feet of gas per day deep within the Egypt Valley area near Morristown.

Some property owners have received at least as much as $6,000 per acre, with as much as 20 percent of the production royalties. Much of the high value for the gas underlying parts of Belmont County is that it contains wet ethane, propane, butane, pentane and oil – in addition to the dry methane gas.

Antero has signed the village of Barnesville to a drilling contract, along with many individual landowners in the community. The deals call for Antero to pay $5,700 per acre to lease the land and 20 percent of production royalties once the gas starts pumping. The company is also paying the Barnesville Exempted Village School District more than $400,000 in lease payments for the rights to extract gas from school property.

County Recorder Mary Catherine Nixon and her staff first started seeing an increase in activity about three years ago, a time when drillers were first considering Belmont County as a target for horizontal drilling and fracking. The traffic has increased during the interim period, largely due to positive drilling results.

In Monroe County, Carr said a single Utica Shale well drilled by Antero Resources could be producing as much as $300,000 worth of revenue per day.

“The well production will decline, but you are talking roughly $2 million per week in gross revenues,” said Carr. “If production holds up for even a short period of time, the well should pay out in two to three months.”

Gulfport’s Clay 3-4H well, just west of Piedmont Lake in Harrison County, is now in production. The well reached a peak daily production rate of 2.5 million cubic feet of natural gas, along with 392 barrels of condensate and 323 barrels of natural gas liquids, such as ethane, propane and butane.

On the West Virginia side of the Ohio River, abstractors are back at work in Ohio County, after they had left for a few months. In Tyler County, officials eventually had to limit access to County Clerk Theresa Hamilton’s office because there just was not enough room in the records vault. This had some abstractors waiting outside all night to secure their places in the records office for the next day, until officials came up with a more organized plan. (Just south of Tyler County, the Pleasants County courthouse is now active also.)

Horizontal Well Testing

Company president advocates direct testing of selected stages in each horizontal well bore.

From the Calgary Herald, Canada, November 22, 2012

The energy industry is pouring vast amounts of horsepower, water and money into shale formations with little or no proof it’s the most cost-effective practice, says Ron Craik, president of Horizontal Well Testing Ltd. This company has patents on testing tools he says will ultimately save money, times and reduce the environmental footprint of horizontal drilling and formation fracturing.

Schlumberger CEO Paal Kibsgaard has recently called established practices “indiscriminate fracking.” Kibsgaard was referring to the use of 10 to 20 staged fracture operations performed on a single, very long horizontal well to access oil or natural gas.

In the past five years the routine use of horizontal drilling and multi-stage fracking has exploded in North America, accounting for 60 per cent of wells drilled in the United States and up to 80 per cent of wells in Canada. Multiple, very-high-pressure, hydraulic fractures are used to break open vast and previously uneconomic shale formations, /releasing billions of dollars worth of new oil and gas production every year.

So-called ‘horizontal multi-fracks’ have become so successful and widespread that the U.S. expects to reverse its dependence on increasing supplies of foreign oil, eliminating some 12 million barrels of daily crude imports and becoming self sufficient within a decade.

But Craik says new production is costing far more than it should — and volumes could fall off just as fast as they rise. “They’re using brute force on these formations without ever really knowing what’s down there or how much they’re leaving behind when those wells water out,” he says. They often water out, not because of resource depletion, but because they’ve been fractured in the wrong places, Craik says.

While horizontal wells frequently cost $5 million each, Craik estimates $2 million to $3 million of that is wasted on fractures that are actually damaging productivity, as well as on drilling wells farther out than they can be effectively produced. While wells are often drilled up to 1.5 kilometres in horizontal reach, there’s increasing suspicion that no significant production is achieved beyond 800 metres. Testing, says Craik, would resolve the debate.

Schlumberger’s Kibsgaard told an energy conference in New Orleans that increased use of seismic technology and computerized reservoir modeling are needed to end the ongoing waste of money and water resources. But Craik advocates direct testing of selected stages/zones in each horizontal well bore to identify where fracturing should and should not be done.

Meaningful testing of horizontal wells has been difficult because established methods developed for conventional vertical wells often rely on drill string rotation for the operation of mechanical tools. Turning the drill stem is a cumbersome and imprecise business when wellbores are deviated by 90 degrees underground.

Craik says his company can provide quick and accurate testing of horizontal wells because it holds the patents on a complete system of electronically-controlled testing tools that can be delivered downhole on a drill string and remotely controlled by wireline connection to a laptop-computer-and-mouse arrangement on the surface.

Testing tools are similar to mechanical “straddle-inflate” systems, but electronically operated. The key difference is electronic control allows tests to be conducted reliably in horizontal wells, where mechanical control is difficult and unreliable. Inflatable packers are placed on either end of a section of drill string with an open-and-close valve between packers. This assembly is placed into the desired test section of the well, packers are inflated to seal off the section and the valve is opened to allow production to flow into the drill stem. Measurements are taken and results are relayed to the surface.

Judicious use of well testing could prevent fracturing water-filled portions of a formation that choke off production, argues Craik. Testing, he says, would also show whether wells are able to produce beyond 800 metres.

Craik and Kibsgaard are running head-on into the industry dogma of “repeatability” — that the best way to attack vast expanses of shale is to rapidly drill large numbers of wells in quick succession, cutting costs by reducing drilling time. This logic has extended to quickly fracturing the entire length of each well and moving on to the next. Anything that slows down drilling and completion increases costs.

Also, testing can be selective. The first well in a formation might be fully tested and mapped, with one or two successive wells spot-tested to reliably map water flows, natural fractures and areas of best permeability. A great deal of unnecessary fracturing could then be eliminated and water flows that choke off hydrocarbon production could be avoided.