Wonders of US Shale: US Shale Benefits: The U.S. leads global petroleum and natural gas production with record growth in 2018

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U.S. shale oil output to rise to record 8.8 million bpd in October: EIA

 

https://www.reuters.com/article/us-usa-oil-productivity/u-s-shale-oil-output-to-rise-to-record-8-8-million-bpd-in-october-eia-idUSKBN1W12CN

 

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North Dakota drillers set oil production record in July

 

 

https://apnews.com/c53e60ed756f498a9084448f5d78db3f

 

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In the last 12 months, a record volume of LNG projects reached final investment decision. These totaled more than 80 million tonnes/year of new production, or 25% of the current market, according to an outlook by McKinsey & Co.

According to the report, “Global Gas & LNG Outlook to 2035: H1 2019,” more than half of global natural gas supply growth until 2035 will be sourced from the US: 380 billion cu m (bcm) out of 635 bcm.

McKinsey’s report, released in September as part of its Energy Insights series, went on to note that China, South Asia, and Southeast Asia will account for 95% of global LNG demand growth through at least 2035. More than 100 LNG liquefaction projects totaling 1,100 million tpy are competing to fill a 125 million-tpy supply shortfall projected over that period. Only 1 in 10 of these will be competitive enough to reach FID, the consultancy said.

“We see abundance of supply, going forward,” McKinsey partner Dumitru Dediu told Oil & Gas Journal at Gastech 2019 in Houston. “We also see Qatar making progress towards FID. Demand continues to grow, but supply is likely to grow even faster. This creates a very difficult situation for suppliers trying to secure demand [in advance of FID].”

Dediu continued, “We don’t see the becoming easier, especially for single-source suppliers. The ones who will actually benefit most will be portfolio players, who can absorb the volumes while taking on and managing the risk.” LNG producers “can only find certainty in projects which can deliver into Asia at below $7/MMbtu,” he said.

Dediu divides LNG importing countries with potential interest in floating regasification into two categories: those replacing or supplementing their own production with LNG (Thailand, Pakistan) and therefore already having the support infrastructure in place and those where grid and other development is still needed. In the latter case, many opt for a direct gas-to-power option with the power then delivered through the electrical grid. Others, such as Brazil, position regasification near an already active industrial site and use the gas there. Either of these options requires engaging a broader spectrum of stakeholders than do new sales into more established LNG buyers.

On the liquefaction side, Dediu expects the modularization of processes undertaken for the Prelude floating LNG project offshore Australia to continue being adapted for both floating and land-based developments, citing nearshore gravity-based Arctic LNG 2 and Coral LNG prime examples. “Going forward, many of the pure floating solutions will be relatively expensive” leading to a mix of floating, nearshore, and gravity-based approaches made possible by the increased modularization.

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West Virginia Emerging as a Natural Gas Powerhouse

 

As it turns out, Pennsylvania is not the only Marcellus shale state with amazing production results. Long a mainstay of U.S. coal production, neighbor West Virginia has quickly become the 7th largest U.S. natural gas producer. Since the shale revolution took flight in 2008, gas output in the state has boomed more than sevenfold to 1.8 Tcf in 2018. West Virginia’s gas production has reached a record for 10 straight years and now accounts for 5-6 percent of total U.S. output. Ranked fourth nationally, West Virginia today holds around 35 Tcf of proven gas reserves. Overlying the Utica play as well, shale now accounts for 95 percent of West Virginia’s gas output. In particular, two of the state’s largest producers, Southwestern Energy and EQT, have impressively responded to a lower priced environment in the shale-era by deploying constantly evolving technologies and operational efficiencies.  

New pipelines have come online to ship West Virginia’s gas to markets in the Northeast, Midwest, southern Canada, and the Gulf Coast. The state now has over 4,000 miles of interstate and intrastate gas pipelines. Per EIA, West Virginia has 31 underground natural gas storage fields that have a storage capacity of 535 Bcf that accounts for almost 6 percent of the nation’s total. The proximity of this gas to high demand markets makes West Virginia a key supplier to surrounding areas during the winter months when usage peaks 40-60 percent.

Indeed, West Virginia still gets 90-95 percent of its electricity generation from coal, with only 2 percent coming from gas. This is in contrast to fellow Appalachian shale giants Ohio and Pennsylvania, two longtime coal states that seek to displace with more gas. This lower domestic reliance on gas will allow West Virginia to remain critical in supplying gas to other states and even LNG export facilities to nations abroad.

There are $30-35 billion, 25 ~Bcf/d of takeaway capacity now in the works in Appalachia, pipelines that will heavily rely on West Virginian supply. These projects are essential across a number of areas: Appalachia accounts for 37 percent of total U.S. gas supply. And at 235,000 MW, EIA has gas adding the most power capacity in the decades ahead, 35 percent more than solar and nearly 10 times more than wind. Up from almost 45 percent today, gas is quickly rising toward being an overwhelming 50 percent of total U.S. power capacity.

 

 

 

Shale production in West Virginia is also bringing mounting supplies of gas liquids, such as ethane and propane. These are feedstocks for manufacturing and making plastics. In Pennsylvania, for instance, Shell is now building the first ethane cracker outside of the Gulf of Mexico in over 20 years. In fact, DOE Secretary Rick Perry wants Appalachia’s shale to turn the region into an industrial hub of global significance. Just recently, West Virginia Gov. Jim Justice signed an executive order for a task force to create more downstream manufacturing opportunities as the industry continues to expand.

The West Virginia Chamber of Commerce is also touting the economic benefits of natural gas for the Mountain State. West Virginia’s GDP per capita is almost 30 percent below the national average, and shale gas offers economic diversification for its embattled coal industry. To illustrate, the $6 billion Shell cracker in Pennsylvania is expected to bring 7,400 permanent jobs and untold billions in tax revenues. The gas boom is a driver for other industries, such as the steel business that enables the shale industry’s fittings, gauges, and other heavy equipment used.

Finally, although offering both controversy and skepticism, West Virginia’s shale is still waiting on a game-changing $84 billion, 20-year investment promised by China. Some 21 months after the non-binding deal was announced, China Energy Investment Corporation has still not spent any money in West Virginia’s energy projects. Hampered by the U.S.-China trade war, officials note how even 10 percent of that amount would be of enormous benefit.

 

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Natural gas royalties projected to jump in Pennsylvania

 

Last year's double-digit increases in production and higher prices for the region's natural gas combined for larger royalties for Pennsylvania landowners in 2018, according to a new state report.

The Independent Fiscal Office estimated residents' income from natural gas royalties rose by double digits for the second year in a row for a total of $1.64 billion, which is the highest in the nine-year period of the Marcellus Shale boom. The estimate released Monday said that was higher than the $1.05 billion for the 2017 tax year, which itself was up 64 percent from 2016's $645 million.

The 2016 total had been the lowest point since 2010 and two years of declines due to lower natural gas prices and the previous slowdown in the industry.

"Compared to 2017, the average spot price (for natural gas) at major Pennsylvania hubs increased by more than one-third, while total output increased by 14 percent," the IFO said in its report. "If those gains were passed through to landowners, then royalty payments would increase by roughly 50 to 55 percent."

It's an estimate because the IFO doesn't get actual data from either the companies or the landowners themselves about the amount of royalty payments, which by law have to be at least 12.5 percent and are an average 13.5 percent. Royalty income are along with copyright and patent income so it has to be estimated.

In 2017, the county with the highest amount of royalty payments was Washington County, with an estimated $264 million. It was followed by Susquehanna ($204 million), Greene County ($129 million) and Butler County ($115 million).

 

 

 

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Like fine whisky, Texan oil exporters tout unblended crude

 

https://www.reuters.com/article/us-usa-crude-corpus-christi/like-fine-whisky-texan-oil-exporters-tout-unblended-crude-idUSKBN1W809R

 

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Eagle Ford Soars On

The Eagle Ford Shale play continues to deliver a steady supply of resources.

 

 

The discovery of the Hawkville Field in October 2008 kicked off a drilling and development boom the likes of which South Texas had not seen before. The discovery well—the STS-241 #1H, drilled by Petrohawk Energy Corp. in LaSalle County—would be the first of many horizontal wells in the Eagle Ford Shale play. In the 11 years since that initial discovery, the play is now considered one of the most mature unconventional plays, with more than 25,000 horizontal wells spudded, according to Drillinginfo.

In an exclusive report provided to E&P, Drillinginfo projects a 4% increase in production guidance from the Eagle Ford, forecasting third-quarter 2019 oil and gas production of 1.43 MMbbl/d and 194 MMcm/d (6.87 Bcf/d), respectively. For year-end 2020, oil and gas projected production is 1.49 MMbbl/d and 193 MMcm/d (6.82 Bcf/d), according to the report.

 

 

 

 

 

 

 

 

 

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Despite Bankruptcies, US Shale is Not Doomed

While news of bankruptcies among U.S. onshore exploration and production (E&P) companies seems to be more frequent these days, Rystad Energy doesn’t believe this indicates doom for the shale industry.

“In a nutshell, we do not believe the recent bankruptcies that have beset a number of shale players are indicative of an industry-wide epidemic,” said Alisa Lukash, a senior analyst on Rystad Energy’s North American Shale team.

Some of those recent bankruptcies include Halcon Resources Corporation, Sanchez Energy Corporation and Alta Mesa Resources, Inc.

Rystad forecasts that the top 40 U.S. shale oil producers will spend about $100 billion in the next seven years on debt installments and interest unless further debt refinancing is applied.  

This group of producers accounted for nearly half of U.S. shale crude production in 2018, according to Rystad, and are now faced with interest payments between $2.6 billion and $5.1 billion annually. Maturities amount to about $71 billion between 2020 and 2026.

A total of $23.7 billion in cash flow from operations was generated in the first half of 2019 with spending being $28 billion on capital expenditures. Rystad sees more than $112 billion in outstanding debt for this group, with a combined enterprise value of $355.5 billion as of September 2019.

“These numbers indicate a lack of financing to deal with the burden of the obligations,” said Lukash. “Given the low levels of external capital additions during the past 10 months, the probability of debt refinancing in the coming quarters seems relatively slim.”

And although Rystad expects more acreage restructuring and mergers and acquisitions (M&A) activity in the industry, they maintain that many operators have combined production growth with balanced spending and debt reductions.

“One should be careful about extrapolating on the basis of a few distressed companies,” Lukash said. “The peer group is very diverse both in terms of acreage quality and in capital efficiency.”

 

 

 

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Permian Oil and Gas to Support 93,000 Jobs in 2020

 

 

The Permian Basin oil and gas industry will support 93,201 jobs in 2020, according to the latest forecast from the Texas Independent Producers & Royalty Owners Association (TIPRO).

This is 5,578 more jobs than the sector supported in the first half of 2019 and 12,209 more jobs than the sector supported last year, TIPRO revealed.

“Based on TIPRO’s analysis, including production, pricing and employment trends, we forecast an increase of 5,500 net new oil and natural gas jobs in the Permian between 2019 – 2020,” TIPRO President Ed Longanecker told Rigzone.

“Permian production and employment are expected to rise in the coming year as additional pipeline capacity comes online,” he added.

The TIPRO head also warned, however, that employment growth will be dependent on several factors and could be negatively impacted by the escalating trade war with China and growing uncertainty in the market among investors and producers. 

1H 2019 Permian Job Data

According to the latest TIPRO figures, Midland, Texas, was the Permian Basin city with the most unique oil and gas job postings (UP) from January to July this year. Registering 2,328 UPs during the period, Midland ranked above Odessa, which saw 1,296 UPs and Carlsbad, which saw 537 UPs.

Delek US Holdings Inc. had the most UPs in the Permian Basin from January to July, TIPRO highlighted. The business recorded 576 UPs during the period, beating out Basic Energy Services Inc., which had 552 UPs in the region and Baker Hughes Inc., which had 426 UPs.

TIPRO showed that the occupation with the most UPs in the region from January to July was general maintenance and repair workers. This occupation had 711 UPs during the period, compared to heavy and tractor trailer truck drivers, which came in second with 598 UPs, and retail salespersons, which came in third with 319 UPs.

The oil and gas industry with the most UPs in the Permian from January to July was crude petroleum extraction, with 2,141, according to TIPRO. Support activities for oil and gas operations saw 1,197 UPs in the region during the period and petroleum refineries saw 1,029 UPs.

1H 2019 Texas Job Data

The oil and gas industry supported 365,511 direct jobs in the state of Texas during the first half of the year, TIPRO’s 2019 Midyear Texas Energy Report showed. The figure represents an increase of nearly 10,000 jobs over the previous year, TIPRO noted.

Oil and gas jobs in Texas paid an annual average wage of $130,706, or 134 percent more than the average private sector job in the state, the report found. The annual payroll for the Texas oil and natural gas industry was said to have exceeded $47 billion in the first half of 2019.

“The Texas oil and gas industry remains a powerful employer in the Lone Star State, as evidenced by findings of the new mid-year TIPRO report,” Eugene Garcia, chairman of TIPRO, said in a statement sent to Rigzone at the end of August.

“In the first half of the year, the Texas oil and gas industry accounted for 40 percent of all oil and gas jobs nationwide,” he added.

Texas Oil Employees Making Life Better

Todd Staples, the president of the Texas Oil and Gas Association (TXOGA), expressed in a statement sent to Rigzone that employees of the Texas oil and natural gas industry are “making life better” for people in Texas and across the world.

The TXOGA head noted that oil and natural gas are the “building blocks of 96 percent of the everyday essentials we use” and said the women and men who work in the Texas oil and natural gas industry “are growing our economy, funding our schools, building our roads, and most importantly, they’re securing our future”.

In a statement posted on its website back in August, TXOGA highlighted that billions of dollars from Texas oil and natural gas activity is paid each year into the state’s Permanent School Fund and Permanent University Fund. 

The statement added that the industry is investing “untold time, talent and treasure” in Texas schools, and their students and teachers, through “innovative education programs and productive partnerships”.

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Gulf Coast Express pipeline starts gas flow

The Gulf Coast Express (GCX) pipeline project has started full commercial operation on Sept. 25, says Kinder Morgan Inc. (KMI), the natural gas system’s builder and operator.

Sep 25th, 2019

The Gulf Coast Express (GCX) pipeline project has started full commercial operation on Sept. 25, says Kinder Morgan Inc. (KMI), the natural gas system’s builder and operator. Construction on the line began in early 2018 (OGJ Online, Jan. 3, 2018).

The pipeline will deliver gas from the Waha Hub near Coyanosa, Tex., in the Permian basin to Agua Dulce, Tex. The $1.7-billion project was originally expected to be online in October.

The GCX project mainline portion consists of 82 miles of 36-in. pipe and 365 miles of 42-in. pipe. The system’s 2-bcfd capacity is fully subscribed under long-term contracts, KMI said.

 

KMI subsidiary Kinder Morgan Texas Pipeline LLC holds 34% in the project. Equity holders include Altus Midstream Co., DCP Midstream LLC, and an affiliate of Targa Resources Corp.

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'Smart' Appalachian Operators Can Handle Sub $2 Natural Gas

The Appalachian Basin is one U.S. hydrocarbon prospection patch that just keeps on giving natural gas – be it via conventional or unconventional means. It’s what the U.S. Energy Information Administration (EIA) describes as the ‘Appalachia Effect.’

For the number crunchers in the market that effect has translated into an uptick in production from 7.8 Bcf/day in 2012 to 23.8 Bcf/day in 2017. That’s a higher natural gas yield than any other OPEC producer, and the primary reason the U.S. has been propelled up the market leaders’ board, with the Appalachian Basin accounting for nearly 50 percent of headline American production.

And there’s more on the way, for the EIA’s latest outlook projects the region’s production to rise to 50 Bcf/day by 2050, with a veritable who’s who of the industry wanting in on the act. Conventional production aside, rising shale gas output from the basin’s Marcellus and Utica shales combined is already lending credence to the projection.

Everyone from Range Resources to Chesapeake, EQT Production to CNX Gas Co., is vying for hydrocarbon molecules in the basin that stretches from Ohio to Pennsylvania.

But while reference cases and projections are one thing, operating reality is quite another. Anecdotal and empirical evidence suggests many players are worried about possible sub-$2 MMBtu Henry Hub prices, thus cutting production and divesting assets; a pricing prospect the region faced back in 2012 for broadly similar reasons – oversupply and difficulty in moving the product to market courtesy of pipeline access and capacity issues.

What’s more, natural gas power burn demand across the U.S. Northeast is expected to dip by around 10 percent over the coming months, going by S&P Global Platts’ projections. This could add further seasonal pressure to already existing headwinds.

According to Moody’s, many regional players will cut growth investment and manage their businesses within operating cash flow. This has only become visible in recent months after slower activity in the fourth quarter of 2018 meant the likes of CNX built a backlog of inventory that kept investment up in the first quarter of 2019.

Despite ~$2.5 MMBtu Henry Hub prices, not every regional player is spooked. The current market permutations demand “smart operations,” says Rusty Hutson, Chief Executive Officer of Diversified Gas & Oil (DGO), a London-listed owner, operator and acquirer of conventional mature wells spread across the Appalachian basin.

Speaking to Rigzone, Hutson explained his modus operandi: “We leverage economies of scale to reduce costs. We go for assets many of the major regional players have given up with zero to declining production and turn them around.”

Often overlapping assets shortens well tenders routes and decreases equipment overhead giving players such as DGO the kind of purchasing power that ultimately reduces costs.

Hutson says he’s “completely sold” on the potential of the Appalachian basin and has made acquisitions all around the region from those very players curtailing investment, including multimillion dollar buys via divestment drives initiated by CNX and Anadarko Petroleum.

A signature acquisition in July 2018 saw the company purchase 2.5 million in acreage from EQT Corp.’s Southern Appalachian producing natural gas and oil for $575 million. “The EQT acquisition positions us as the largest conventional producer in the region.”

What Hutson has also managed is a strategic grab of more than 6,400 miles of gathering pipe and 59 compressor stations, via the EQT acquisition which significantly “enhances the economics” of the Company’s production in the Appalachian Basin, given getting product to market is making everyone sweat.

DGO’s headline production is over 90 million barrels of oil equivalent per day (boepd) or ~0.51 bcf/day; a near trebling in output volumes over of period of 12 months. The company’s total valuation of all acquisitions currently stands at $1.3 billion of mainly long-life, low-decline gas and oil producing assets

“Over 80 percent of our current well portfolio will cost less than $25,000 to plug, and cost average is currently in the region of $23,800 per well. Each of our operating areas is supported by multiple pipeline takeaway alternatives.

“These options allow us to redirect gas to more favorable markets and avoid regional capacity constraints in the event of the sort of bottlenecks exploration and production (E&P) companies often complain about.”

Much of DGO’s natural gas is sold on the Trans Columbia pipeline, which has historically traded at ~$0.30 MMBtu improved differential over Dominion South, with the latter pipeline facing the full force of current industry permutations.

“Ultimately it is about cost controls, and we prefer to be an owner/operator model for over 95 percent of our assets with very few contractors and nearly 1,000-odd direct employees running things.”

Yet the price climate cannot be ignored and Hutson says operating pressures are what separate the best from the rest in his playbook.

“We proactively hedge, deploying a mixture of physical and financial contracts to protect our cash flow and minimize commodity price volatility. At $3-4 MMBtu-plus natural gas prices, drilling activity naturally picks up because everybody is doing it! The current climate is what fires up innovators to make a decent buck; we’d like to count ourselves among them.”

 

 

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North Dakota Crude Production Reaches Another Milestone

 

https://finance.yahoo.com/news/north-dakota-crude-production-reaches-132001779.html

 

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On 9/27/2019 at 1:08 AM, ceo_energemsier said:

Gulf Coast Express pipeline starts gas flow

The Gulf Coast Express (GCX) pipeline project has started full commercial operation on Sept. 25, says Kinder Morgan Inc. (KMI), the natural gas system’s builder and operator.

Sep 25th, 2019

The Gulf Coast Express (GCX) pipeline project has started full commercial operation on Sept. 25, says Kinder Morgan Inc. (KMI), the natural gas system’s builder and operator. Construction on the line began in early 2018 (OGJ Online, Jan. 3, 2018).

The pipeline will deliver gas from the Waha Hub near Coyanosa, Tex., in the Permian basin to Agua Dulce, Tex. The $1.7-billion project was originally expected to be online in October.

The GCX project mainline portion consists of 82 miles of 36-in. pipe and 365 miles of 42-in. pipe. The system’s 2-bcfd capacity is fully subscribed under long-term contracts, KMI said.

 

KMI subsidiary Kinder Morgan Texas Pipeline LLC holds 34% in the project. Equity holders include Altus Midstream Co., DCP Midstream LLC, and an affiliate of Targa Resources Corp.

There's been much talk of Permian producers losing revenue to restricted output and low prices due to a glut of natural gas.  To what extent will this pipeline help their situation?  Does it end the crisis, or will that require more pipelines?

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6 hours ago, BenFranklin'sSpectacles said:

There's been much talk of Permian producers losing revenue to restricted output and low prices due to a glut of natural gas.  To what extent will this pipeline help their situation?  Does it end the crisis, or will that require more pipelines?

This will definitely help and other pipelines for natgas and oil are under way that will increase the take away capacity to the USGC from the Permian, great refining and petchem region and export markets.

I had discussed about other options to end and or minimize the natgas flaring and put that gas to good under a different topic , I think it was under gas flaring .

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16 hours ago, ceo_energemsier said:

This will definitely help and other pipelines for natgas and oil are under way that will increase the take away capacity to the USGC from the Permian, great refining and petchem region and export markets.

I had discussed about other options to end and or minimize the natgas flaring and put that gas to good under a different topic , I think it was under gas flaring .

Do you have any thoughts on the timelines of these other projects, what they will do to wellhead prices of natural gas, and how that will affect producers?  This isn't an area I'm familiar with. 

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On 9/29/2019 at 5:20 AM, BenFranklin'sSpectacles said:

Do you have any thoughts on the timelines of these other projects, what they will do to wellhead prices of natural gas, and how that will affect producers?  This isn't an area I'm familiar with. 

 

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US shale and a glut of crude will prevent Saudi oil shock

Texas’ thriving oil production could be to thank for the world avoiding an economically crippling, triple-digit spike in crude prices following attacks on facilities in Saudi Arabia less than two weeks ago.

Fears of soaring prices and panic buying at petrol pumps failed to materialize, despite the temporary loss of 6% of the world’s supply from Saudi oil wells. Instead of an oil shock spiraling out of control after prices initially surged by a record 20%, crude was trading on Friday only fractionally higher than its $64/b year-to-date moving average.

 

Saudi Aramco can claim some of the credit for steadying the ship. The kingdom’s national oil company has pledged to restore its capacity to 11 million b/d by the end of the month, after losing half of its output following the attacks. Meanwhile, it will honor all of its contracts to supply customers with crude from existing stockpiles, while engineers try to rebuild bombed out facilities at Abqaiq and Khurais.

 

 

 

 

 

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Tsunami on the shale

Loving County had 82 residents in the last census. Now, an oil boom pumps billions of dollars into the once-idle town. The local convenience store sells 1,200 cases of beer a week, and it can take 47 minutes to get through a stop sign.

 

https://www.expressnews.com/news/local/article/Oil-boom-hits-remote-Loving-County-14467872.php

 

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some great data here.  but how long can shale last, and at what enviro cost? 

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Small-scale LNG

making market

inroads

Overshadowed by their bigger, more eye-catching counterparts,

small-scale LNG projects in fact make up the majority of US LNG

facilities.

 

 

 

https://plattsinfo.spglobal.com/rs/325-KYL-599/images/PL-APPEC_Insight_Small-scale-LNG-making-market-inroads.pdf?mkt_tok=eyJpIjoiTVdGa00yTTFNakkzTXpnMiIsInQiOiJodnI1YXNtelBrM3RubFhOTUY5U0RaNkkrRzdEeDViRlZWWjlCMGhsanFFa1NOQXZTZiswU3J0MndIaHhHclJ6YXI0V0VJeUtMZ2VTRFdmczVUc0UrNUdNS2hEdFFzSFwvNUJCYTlRVE5pZmQ0Nkcyekk3WGh5ZHNqV0x5QWxqVFcifQ%3D%3D

 

 

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By U.S. Geological Survey | October 08, 2019

 

he Marcellus Shale and Point Pleasant-Utica Shale formations of the Appalachian Basin contain an estimated mean of 214 trillion cubic feet of undiscovered, technically recoverable continuous resources of natural gas, according to new USGS assessments.

“Watching our estimates for the Marcellus rise from 2 trillion to 84 trillion to 97 trillion in under 20 years demonstrates the effects American ingenuity and new technology can have,” said USGS Director Jim Reilly. “Knowing where these resources are located and how much exists is crucial to ensuring our nation’s energy independence.”

The Marcellus, Point Pleasant and Utica are extensive formations that cover parts of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia.

This is a significant increase from the

previous USGS assessments of both formations. In 2011, the USGS estimated a mean of 84 trillion cubic feet of natural gas in the Marcellus Shale, and in 2012 the USGS estimated about 38 trillion cubic feet of natural gas in the Utica Shale.

Significant amounts of natural gas have been produced from the Marcellus and Utica Shales since the previous USGS assessments. USGS assessments are for remaining resources and exclude known and produced oil and gas.

The natural gas in these formations is classified as continuous, because it is spread throughout the assessed rock layers instead of being concentrated in discrete accumulations. Production techniques like directional drilling and hydraulic fracturing are required to produce these resources.

“Since our assessments in 2011 and 2012, industry has improved upon their development techniques for continuous resources like the shale gas in the Appalachian Basin,” said Walter Guidroz,  program coordinator for the USGS Energy Resources Program. “That technological advancement, plus all of the geological information we’ve gained from the last several years of production, have allowed us to greatly expand our understanding of these formations.”

The Marcellus Shale also contains an estimated 1.5 billion barrels of natural gas liquids, while the Point Pleasant-Utica Shale also contains an estimated 1.8 billion barrels of oil and 985 million barrels of natural gas liquids. Natural gas liquids are liquid hydrocarbons like propane, butane and/or ethane.

These assessments are for undiscovered, technically recoverable resources. Undiscovered resources are those that have been estimated to exist based on geology and other data, but have not yet been proven to exist by drilling or other means. Technically recoverable resources, meanwhile, are those that can be produced using today’s standard industry practices and technology. This is different from reserves, which are those quantities of oil and gas that are currently profitable to produce.

USGS is the only provider of publicly available estimates of undiscovered technically recoverable oil and gas resources of onshore lands and offshore state waters. The USGS Marcellus and Point Pleasant-Utica Shale assessments were undertaken as part of a nationwide project assessing domestic petroleum basins using standardized methodology and protocol.

 

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Oil Exports, Lower Net Imports, Greater Energy Security

 

https://www.api.org/news-policy-and-issues/blog/2019/10/04/oil-exports-lower-net-imports-greater-energy-security

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Producing Energy, Reducing Emissions in New Mexico

 

https://www.api.org/news-policy-and-issues/blog/2019/10/08/producing-energy-reducing-emissions-in-new-mexico

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Permian Serves As Oil Market Shock Absorber

 

For the oil market, the Permian Basin acts like a shock absorber.

That is a key takeaway from a new report from Austin, Texas-based oil and gas software-as-a-service (SaaS) and data analytics firm Enervus. The report examines geopolitical and domestic impacts affecting the oil, natural gas, and natural gas liquids (NGL) markets.

“Global incidents like the attack on Saudi oil facilities that used to send lasting ripples across the world and disproportionately harm the United States are now being dismissed,” Bernadette Johnson, vice president of strategic analytics at Enervus, said in a written statement emailed to Rigzone. “What used to trigger a major buy or sell in crude oil, or cause prices at the pump to skyrocket, are being shrugged off by the markets in a day.”

Johnson pointed out that markets have abundant U.S. supplies – primarily from the Permian Basin – to thank.

“Absorbing most of that impact is the Permian Basin, which has since jumped to 40 percent of total U.S. oil production, but capacity and bottlenecks continue to be a major problem there,” said Johnson. “The good news is relief is on its way with several planned pipelines expected to come online soon.”

Beyond last month’s disruption in Saudi production, steep declines in crude output from Iran and Venezuela have failed to present physical oil markets from being well-supplied, Enervus also noted.

“Preliminary data imply global petroleum stocks drew in the third quarter and stocks are expected to draw again in the fourth, but large supply/demand imbalances are in our outlook for early 2020 as total petroleum demand continues to soften and non-OPEC production ramps up further,” the firm stated.

In fact, despite the ostensible slowdown in U.S. tight oil production, Enervus contends that production growth in Brazil and Norway will augment U.S. supplies and drive non-OPEC crude and condensate growth to 2 million barrels per day in 2020.

The report also anticipates continued robust growth in exports of U.S. liquefied natural gas (LNG) – provided that international trade disputes do not derail the trend.

“America’s energy story isn’t just about crude oil,” continued Johnson. “LNG exports set a record high during the summer of 2019, and our projections indicate they could nearly double from 5.0 billion cubic feet per day (Bcfd) to 9.0 Bcfd by 2023. However, trade wars could certainly alter that anticipated future.”

On the NGL front, Enervus observes that record or near-record production and inventory levels have depressed ethane and liquefied petroleum gas (LPG) prices. Moreover, the company noted that a “slew of fractionation capacity” is slated to come online during the first quarter of 2020; but, it added that Mother Nature could alter that schedule.

“However, recent storms and flooding along the Texas Gulf Coast near Mont Belvieu may delay some of these projects, possibly extending fractionation tightness along the Gulf Coast as y-grade production continues to increase, particularly out of PADD 3 and the Permian,” Enervus stated.

Enervus, which until late August was known as DrillingInfo, has posted a preview version of its new 50-page report, “The Street Strikes Back.”

 

https://gallery.mailchimp.com/14d8055a9f17567db04b7ce70/files/1853d148-be58-4eb0-a3d8-c61c25c8ba28/EnverusDI_THE_STREET_STRIKES_BACK_OCT2019_PREVIEW.pdf