US Shale: Technology

[Wombat + 1,028]

16 hours ago, Douglas Buckland said:

Better you switch to gold as you do not seem to know much about oil. Good lick!

I know just enough about oil to know there is massive oversupply at the moment and I won $2000 on gold this morning which covers about a third of my losses on my oil company investment. Rest is in pharmaceutical distribution companies.

[Douglas Buckland + 6,308]

7 minutes ago, Wombat said:

I know just enough about oil to know there is massive oversupply at the moment and I won $2000 on gold this morning which covers about a third of my losses on my oil company investment. Rest is in pharmaceutical distribution companies.

Okay, now you being up an interesting point! How do you know that there is a ‘massive oversupply’? Where are you getting your data? The only region that even attempts to track supply/storage is North America via the weekly EIA questionaries (polls), then their monthly summary. Nowhere else on the planet is verifiable data available/published!

There is absolutely no factual, verifiable, volumetric data available.

[Wombat + 1,028]

1 minute ago, Douglas Buckland said:

Okay, now you being up an interesting point! How do you know that there is a ‘massive oversupply’? Where are you getting your data? The only region that even attempts to track supply/storage is North America via the weekly EIA questionaries (polls), then their monthly summary. Nowhere else on the planet is verifiable data available/published!

There is absolutely no factual, verifiable, volumetric data available.

Not much, that is true. Apart from US, only Europeans publish the data. I know that Saudi Arabia had about 270 mb before their facilities got attacked (from article about satellites monitoring shadows of their storage tanks), but I guess they used it all up and have just got production back on line and re-filling their tanks as we speak?

[Douglas Buckland + 6,308]

BUT....all this published data cannot be verified in ‘real time’. Using satellites to judge the level in storage tanks with floating tops is fine I suppose....if you have enough satellites to monitor ALL the floating tops in EVERY tank farm in the world. For tanks with fixed tops, you have no idea what is in them.

The point being, we have absolutely no accurate idea as to how much oil is in storage globally at any given time.

Furthermore, with global production being what it has been for the past 5 years and considering the decreasing rate of demand during the same period....shouldn’t every storage tank available be full?

Something just does not seem to add up.

[Wombat + 1,028]

2 hours ago, Douglas Buckland said:

BUT....all this published data cannot be verified in ‘real time’. Using satellites to judge the level in storage tanks with floating tops is fine I suppose....if you have enough satellites to monitor ALL the floating tops in EVERY tank farm in the world. For tanks with fixed tops, you have no idea what is in them.

The point being, we have absolutely no accurate idea as to how much oil is in storage globally at any given time.

Furthermore, with global production being what it has been for the past 5 years and considering the decreasing rate of demand during the same period....shouldn’t every storage tank available be full?

Something just does not seem to add up.

Well, back in 2015, we ended up with 100 VLCC's being anchored in a port near Manila. "Floating storage" probably rising as we speak? I do agree, however, that these things should be publicised more.

[Wombat + 1,028]

2 minutes ago, Wombat said:

Well, back in 2015, we ended up with 100 VLCC's being anchored in a port near Manila. "Floating storage" probably rising as we speak? I do agree, however, that these things should be publicised more.

PS: Chinese have building their own "strategic reserve" but last I heard, that was completed about 6 months ago. Also, they reckon that Chinese demand now down by 2-3mbd, so it has to go somewhere? Exactly where, I dunno. Maybe we should ask Tom?

[Douglas Buckland + 6,308]

1 hour ago, Wombat said:

Well, back in 2015, we ended up with 100 VLCC's being anchored in a port near Manila. "Floating storage" probably rising as we speak? I do agree, however, that these things should be publicised more.

You mean to tell me that somebody actually rented 100 VLCC’s (at some unbelievable dayrate) to store oil? Not saying you’re wrong, just hard to figure out the logic. Wouldn’t it have been cheaper to build a tank farm....or simply stop importing what you couldn’t use in a timely manner?

[Tom Kirkman + 8,860]

2 hours ago, Wombat said:

PS: Chinese have building their own "strategic reserve" but last I heard, that was completed about 6 months ago. Also, they reckon that Chinese demand now down by 2-3mbd, so it has to go somewhere? Exactly where, I dunno. Maybe we should ask Tom?

Beats the heck outta me.

[Douglas Buckland + 6,308]

1 hour ago, Tom Kirkman said:

Beats the heck outta me.

Strategic reserves are usually stored in old salt mines or some other underground storage solution. I would not think that ‘strategic reserves’ would be included in the surplus equation in any event.

Could be wrong...

[D Coyne + 305]

4 hours ago, Douglas Buckland said:

Strategic reserves are usually stored in old salt mines or some other underground storage solution. I would not think that ‘strategic reserves’ would be included in the surplus equation in any event.

Could be wrong...

Doug,

Absolutely correct we have little clarity on oil inventory, OECD data is about the bast we have and that leaves much of the World out and the data is pretty old, about three to 6 months behind the current date.  One might glean the balance of supply and demand by the direction of oil prices, but often the market expectations are incorrect so this might also lead to incorrect conclusions.

In short, I agree we know very little about oil inventory levels.

Earlier you mentioned decreasing demand, do you mean that the rate of increase in the level of demand, has been lower?  If so, I would agree, if you mean that the level of demand is lower (less oil has been consumed at the World level), I think that is incorrect.

Edited February 10, 2020 by D Coyne

[KeyboardWarrior + 527]

7 hours ago, Douglas Buckland said:

Strategic reserves are usually stored in old salt mines or some other underground storage solution. I would not think that ‘strategic reserves’ would be included in the surplus equation in any event.

Could be wrong...

You mean to say that we can fill old salt mines with OIL? This is the kind of shit I love to ready about. 

Or is the oil in containers? 

Edited February 10, 2020 by KeyboardWarrior

[ceo_energemsier + 1,818]

9 hours ago, Tom Kirkman said:

Beats the heck outta me.

Hi Tom,

How have you been? hope all is going well.

 

The Chinese started building their strategic reserves starting sometime between 2009-2010. They have a combo of UST (underground storage tanks) as well as above ground. The Chinese gov also gave licenses to private companies to start importing crude and building reserves, which caused a bump in Chinese crude demand in addition to new refineries (indie and soe) coming online.

They have more than 1bil bbls of strategic reserves capacity and are still not done building them. Reliable data is hard to come by in relation with China and oil etc but from what I hear regarding this , they are still at it building more and more. They have not used many salt caverns in China because of seismic activities in the areas where they want them.

 

But they are still building their strategic reserves , so I say keep building them and I will keep selling you as much oil I can get my hands on to fill em up!!! haha

 

In the US, the DOE has the SPR which is stored in salt caverns, in addition to man made storage tanks UST and otherwise as well as private companies in the US have a lot of storage capacity.

 

Salt caverns are also used for storing natgas and propane etc .

 

India has been building strategic reserves as well in salt caverns and Japan maintains a strategic reserve too.

[ceo_energemsier + 1,818]

8 hours ago, Douglas Buckland said:

Strategic reserves are usually stored in old salt mines or some other underground storage solution. I would not think that ‘strategic reserves’ would be included in the surplus equation in any event.

Could be wrong...

They are not always old salt mines, they can be salt domes or salt deposits that are thick enough that are then "washed out" to make the caverns for storage of crude etc

[ceo_energemsier + 1,818]

11 hours ago, Wombat said:

Well, back in 2015, we ended up with 100 VLCC's being anchored in a port near Manila. "Floating storage" probably rising as we speak? I do agree, however, that these things should be publicised more.

Floating storage is the new thing because of corona these days, Shell, BP, Vitol and others are at it.!!!

[Douglas Buckland + 6,308]

 

“Earlier you mentioned decreasing demand, do you mean that the rate of increase in the level of demand,has been lower?  If so, I would agree, if you mean that the level of demand is lower (less oil has beenconsumed at the World level), I think that is incorrect.”

 

Sorry about that DC, I meant that the rate of demand was decreasing, but overall demand was still increasing. Thanks for pointing that out!

[Douglas Buckland + 6,308]

8 hours ago, KeyboardWarrior said:

You mean to say that we can fill old salt mines with OIL? This is the kind of shit I love to ready about. 

Or is the oil in containers? 

In the US, in the past anyhow, oil was pumped directly into old salt mines for storage....look up ‘US Strategic Reserves.

[Douglas Buckland + 6,308]

7 hours ago, ceo_energemsier said:

They are not always old salt mines, they can be salt domes or salt deposits that are thick enough that are then "washed out" to make the caverns for storage of crude etc

The properties of the salt in relation to oil and the volumetric concerns were the key.

[ceo_energemsier + 1,818]

Permian's Next Chapter

As the world’s most prolific hydrocarbon play evolves, new challenges—and opportunities—have emerged or remained

 

 

 

If the first chapter of Permiania included an acreage grab, drilling bonanza, infrastructure conundrum and other factors associated with the frantic, early stages of development for what has become the most prolific hydrocarbon producing play in the world, the next stage of the Permian’s near-term storyline already appears different. 

Since the introduction and acceptance by industry executives and investors of terms like “within cashflow,” exploration and production companies of all sizes have entered a new operating norm. Shareholders and lenders are now pushing for operators to focus on, or choose, dividend payments and stock buybacks in lieu of production growth, acreage buys or other non-shareholder return-based strategies. Strong financial operators still have the ability and support to make big deals, but the general consensus is that once production is maintained, additional revenue should be spent outside the oilfield.

Throughout 2019, the number of Permian-linked E&P’s implementing their first-ever dividend programs or share buyback events steadily increased. In the present, nearly every producer is pushing a message that clearly indicates to investors and others that success in the Permian isn’t solely about asset growth, delineation in the field or midstream upgrades. Instead, Permian

players from southeast New Mexico across West Texas are now conscious and clear about bringing the value in the field to those that have helped back it. Multiple factors, however—from oil prices to base decline rates to export options—will play a role in the near-future of the Permian’s development. 

All sectors across the play have had to navigate volatile oil prices. The combination of less-than-ideal oil prices with a producer mindset shift away from extreme growth at all costs has caused stress and created impact in the pumping and drilling sector. For much of 2019, the Permian rig count was in decline, along with the number of fracturing crews present. While the Permian boasts some of the best breakeven numbers in all of shale, the lack of infrastructure to handle produced gas or produced water along with the uncertainties of oil or gas takeway and processing capacity has made the allure of the Permian bright but not blazing. The presence of stacked pay and a better understanding of how to use lateral length and completion design to produce more continues to be a driving positive of the Permian. But, global factors, oil prices and a tight-margin world through every sector is pressuring all companies to focus on their core cash-flow generating assets and discard the others.

To end the year, Basic Energy Services and PumpCo announced plans to shutter their respective pumping units. Both chose to focus revenue generated from the sale of pumping assets on other sectors in the Permian. The current play appears to be more about managing upside potential, immediate cash-flow and eliminating non-core assets until general market conditions (guided by oil prices and global economic factors) improve. 

The Permian, despite company moves, time-sensitive assessments on the state of the play, or headlines that seem to indicate a negative direction, is in a class of its own. With more than 350 active drilling rigs and a huge mix of global operators and independents, the play is still positioned to remain a dominant force for global oil and gas production, jobs, and opportunity for years to come. 

Permian: Changing But Staying The Same
Full-service credit rating agency Kroll Bond Rating Agency believes that differentiation in the energy industry in terms of operational and financial risk management has increased. “Some companies are becoming more disciplined in response to the industry’s challenging headwinds, while other energy companies have remained static,” KBRA said. Because investors are seeking returns, many entities may face difficult operating conditions that don’t allow for continued debt use. KBRA believes distressed high-yield energy companies will continue to look at mergers or acquisitions instead of going it alone. 

Several deals from 2019 indicate that no entity is ever free from merging or acquisition plans. Carrizo and Callon Petroleum, both large producers with financial issues related to debt maturities and free cash flow, merged to focus on the Delaware and Eagle Ford. At the end of the year, WPX Energy joined with Felix Energy because in part, Felix leadership said the current operating conditions made their move very relevant at the time. The deal was valued at $2.5 billion. 

Apart from investor sentiment, Permian producers continue to navigate an infrastructure- and midstream-world that can teeter between enough and undersupplied. For a play that produces roughly three barrels of water for every barrel of oil, the Permian’s water handling and takeaway providers have been up to the task of meeting industry needs. More than ten water firms made major moves, added technology, upgraded existing facilities or built new water-based infrastructure in 2019. Companies are finding ways to treat water with floating evaporators, track supplies with satellites or monitor water-contracts with blockchain technology. 

A research study by the University of Houston Research Center indicates that after a difficult 2018 and early 2019, oil takeaway infrastructure is primed to meet demands by the end of 2019. However, oil export infrastructure and gas takeaway, treatment and downstream customer options continue to be an issue. Apache Corp. made headlines in 2019 when it hired a third-party vendor to handle its gas. The E&P ended up paying for an outside party to take its produced gas for a price greater than the gas was worth. The University of Houston Research Center believes that the continued lack of gas takeaway and export infrastructure will harm small, independent producers the most.

“While refineries have increased processing to keep up with production, supply of crude oil will soon outstrip demand and the producers will need to find new customers,” said Ramanan Krishnamoorti, co-author of the research. “Even though there is more than $90B in construction projects for terminals, LNG, refining and petrochemical facilities along the Texas and Louisiana Coast right now, and another $200 billion planned for the next decade, construction can’t keep pace with the supply of oil coming out of the Permian.” 

The rapid growth of production doesn’t appear to be falling below current levels either. Global information firm, IHS Markit, ran the numbers on base decline rates in the Permian and found that wells drilled in the past 1 to 2 years will show a production decrease after the first year of up to 85 percent. But, the research team also said that well production during the first year of a Permian well is so great that the decline rate formula for brining a new Permian well online always makes sense. 

IHS describes base decline rates this way. “Base decline is calculated by identifying the actual or forecasted production of all the wells onstream at the start of the year, then tracking their cumulative decline by the end of the year. Understanding those base declines is critical for engineers/operators who must determine what level of drilling and production targets must be achieved for their company to grow production, and hopefully, maintain performance and provide returns to investors.” 

According to the information giant, oil and gas operators in the Permian Basin will have to drill substantially more wells just to maintain current production levels and even more to grow production. Well spacing and completion strategies could have an impact on the number of wells needed, however. 

Although there are continued issues with infrastructure takeaway, pressures from investors, a diminished participation of certain funding silos, well spacing questions, and other factors to overcome, the opportunity in the Permian remains clear. The massive formation holds more than six (double that depending on who you talk with) known and proven tight oil and gas producing benches. At more than 4 million barrels of oil per day produced, the Permian produces more oil than any shale-based formation. Oil prices will fluctuate for various reasons, but technology continues to improve and extracting hydrocarbons becomes more feasible and efficient every month. The service providers in the drilling, completion, midstream or production sectors that remain fluid and able to meet the ongoing demands of operators will continue to thrive. Operators in strong financial positions will continue producing and growing—either in the field or by acquisition. The first chapter of Permiania may be over.Although there is still acreage that needs to be held by drilling, a majority of the play is transitioning from the initial land grab and prove-out of initial wells and benches. The next era appears to be unmatched in a new way because of the technology entering the play and infrastructure coming online that will drive down operational costs. All of it is best described by an old saying that says big oilfields just keep getting bigger. PR

---

One Operator’s Impact In New Mexico 
ExxonMobil’s Permian development efforts will have a $64 billion impact on the New Mexico portion of the play. As part of ExxonMobil’s Permian Basin growth plans, the company plans to expand its operations to produce more than 1 million oil-equivalent barrels per day as early as 2024. This push will require roughly $55 billion in capital expenditures in Eddy and Lea counties. 

At current funding levels, those contributions would translate to the following: 

• $6 billion for higher education: Enough to pay college tuition for more than 827,000 New Mexico students
• $10 billion for health and human services: Equal to the salaries of more than 146,000 nurses
• $18 billion for New Mexico’s public schools: Equal to the salary of more than 309,000 elementary school teachers
• $6 billion for other state government services: Which is almost equal to the entire 208 New Mexico state budget

---

Workforce Spotlight
To help promote available positions and connect available talent with oil and gas employers, the Texas Independent Producers & Royalty Owners Association outlined the job outlook in the Permian early in 2019.

• From January through February, the crude petroleum extraction sector had the highest number of job openings
• Houston, followed by Midland and San Antonio had the highest number of job postings. 
• The top hard skill listed for open oil and gas positions was oil and gas (19 percent), followed by valid driver’s license (15 percent), and good driving record (10 percent).
• The top common skill listed for open oil and gas positions was management (42 percent), followed by operations (32 percent), and communications (29 percent).
• The top qualification sought for listed open positions was commercial driver’s license (979), followed by Master of Business Administration (226), and Transportation Worker Identification Credential (TWIC) Card (181).
• The leading posting source for open oil and natural gas positions was Nexxt.com (6,491), followed by Workintexas.com (5,218), and My.jobs (3,170).

[ceo_energemsier + 1,818]

Texas RRC commissioner explains flaring in Permian

 

Flaring is a process used primarily in the production of crude oil in which excess natural gas produced with the oil is burned off at the well head. An operator who wants to flare gas must receive authorization from the Railroad Commission of Texas. 

"There are many misconceptions about what flaring is and how much we are flaring in Texas," said Chairman Wayne Christian. "This uncertainty has led to confusion and concern among the general public and on Wall Street, limiting the funding opportunities for independent energy producers across the state." 

To learn more about the process of flaring

and how it is regulated, click here. 

"As I previously stated in an opinion piece for USA Today (read here), flaring is an important part of America’s rise to global energy dominance and is a safer alternative to venting," continued Christian. "However, I am very concerned about the rate of flaring in Texas and have expressed this as the first commissioner in recent memory to vote against a flaring permit."

Last fall, Chairman Christian instructed staff to analyze flaring in Texas. Their analysis shows that the average monthly statewide flaring rate since January 2014 has been about 1.24 percent, fluctuating between 0.8 percent to 2.2 percent. The data is taken from flaring amounts and gas production reported on operators’ monthly production reports to the Commission. 

Operators receiving permits to flare are required to report to the Commission gas volumes flared on their monthly Production Report form (Form PR). On the forms, operators must include actual, metered volumes at the RRC lease level. 

RRC’s flaring rule allows an operator to flare gas while drilling a well and for up to 10 days after a well’s completion to conduct well potential testing. Flaring from wells for extended periods may be necessary if a well is drilled in areas new to exploration where pipelines have not been constructed. Other reasons for flaring include: gas plant shutdowns; repairing a compressor or gas line or well; or other maintenance. In existing production areas, flaring also may be necessary because operating pipelines may have reached capacity. 

“I truly believe much of our state’s flaring will be eliminated as we expand our pipeline capacity and export infrastructure for LNG,” continued Christian. “But in the meantime, I would love to hear suggestions from industry and the public on creative ways we can curb this practice and encourage using this gas for its intended purpose, powering Texas.” 

 

[ceo_energemsier + 1,818]

New Deloitte oil, gas study shows shifting strategies

 

While total oil and gas deal count declined in 2019, total deal value held up thanks to several mega-deals, primarily in upstream and downstream.

-Majors and large independents are expected to drive deal making as they continue to optimize their portfolios and divest higher carbon projects.

-International oil and gas companies will likely continue to expand their downstream footprint to pursue growing demand for petrochemicals.

-Continuing challenging market conditions could drive further U.S. shale sector consolidation in 2020.

 

Bigger was better in 2019

While total deal value in 2019 increased 40 percent to $370 billion, thanks to several upstream and downstream mega-deals, overall deal count declined year-over-year by 40 percent as companies continue to struggle with low commodity prices and challenging market conditions, according to Deloitte's "2020 Oil and Gas M&A Outlook."

A look back at 2019: M&A sector by sector

-Upstream deal values totaled $156 billion, up $26 billion YOY. Only 208 deals were struck, 40 percent below the five-year trend. The U.S. was the hub of global upstream M&A last year, representing more than 60 percent in terms of both deal volume and value.

-Midstream significantly increased in both deal count and deal value in 2019, striking 76 deals worth $78 billion, a 30 percent and 50 percent YOY increase, respectively. Private equity spend increased in this sector as investors pivoted from production to infrastructure.

-Downstream deal value reached $114 billion, a decade high and almost double the prior year and five-year average, while the number of transactions declined 15 percent YOY.

-Oilfield services (OFS) deal making stalled with deal values reaching $19 billion in 2019, down $2.5 billion YOY and 35 percent below the five-year average.Volumes decreased 20 percent YOY, 10 percent below the five-year average.

Key quotes

"As we enter 2020, the new decade seems to be ushering in a new era of oil and gas portfolio design driven by changing shareholder and investor expectations. As portfolio optimization, capital discipline and sustainability issues move increasingly to the core of corporate decision making, the drivers and types of deals will likely evolve,” said Duane Dickson, vice chairman and U.S. oil, gas and chemicals leader, Deloitte Consulting LLP.

"Facing continued headwinds, many private equity firms are being forced to hold their investments for a longer period as an IPO or sale to a corporate buyer is often not a feasible exit strategy, except for the most valuable positions. These challenges are pushing most portfolio companies to focus on operations to generate returns, until an exit can be made,” according to Melinda Yee, partner, Deloitte & Touche LLP.

M&A outlook for 2020:

More of the same, but a little bit different According to the report, absent an increase in commodity prices, the dampened level of deal making activity is expected to continue in 2020. However, as many companies change their portfolios to match external market conditions and their own shifts in strategic priorities, evolving trends and themes could shape the oil and gas transactions market in the year ahead and beyond.

Past M&A to spur future M&A activity:

The largest driver in 2020 divestitures will likely be massive 2018 and 2019 acquisitions. Upstream companies involved in recent deals are expected to continue to realign their portfolios and strategies while also looking for divestment opportunities that allow them to focus on expanded footprints and assets.

Pursuing greener pastures means divesting higher carbon assets

In looking at existing assets, some companies are considering carbon footprints when it comes to divestitures. As investor sentiment has changed, oil companies have increased their discussion of environmental, social and governance (ESG) issues. As the size of ESG investment funds grow, so could oil and gas companies' interests in burnishing their environmental credentials. To that end we will likely see not only increased renewables investment but also carbon-based divestures.

Majors expected to be primary catalyst for global M&A

In 2019, the majors divested a wide swath of assets across a range of geographies and resource types. The pace may slow down this year, but opportunities remain for further portfolio streamlining with some potentially large asset divestitures across U.S. shale plays, the North Sea and Asia-Pacific in play.

Integrated and national oil companies moving onward and downward

To capitalize on growing chemicals demand, most international oil and gas companies are continuing to expand their downstream footprints, beyond refining assets, and into distribution, retail, and chemicals businesses. This investment push, that has primarily targeted integrated refining and petrochemical assets, as well as fuel and natural gas networks in the Middle East and Asia Pacific, is expected to continue.

Capital markets freeze could prompt upstream and OFS consolidation

In 2020, we could see more consolidation of upstream and OFS companies as capital markets refuse to thaw, and topline U.S. production growth continues to decline. Sellers and management teams, however, might need to be willing to forgo significant premiums to get the deals done in order to achieve the synergies and economies of scale that form the strategic basis for executing the deal — which may make stock more palatable as currency.

Private equity strategy shift may bring shale sector consolidation

A pivot in private equity's traditional strategy may accelerate consolidation in shale. With the oil and gas IPO market dead in the water and debt issuance trending monotonically downward since 2014, private equity firms and their portfolio companies are rethinking their traditional build-and-flip strategy. The year 2020 may see the build-to-operate model fully take flight in the Permian and beyond.

 

[ceo_energemsier + 1,818]

E&P-backed shale gas tech firm tests new pump in Indiana

 

Equinor-backed Upwing Energy has gone to Indiana to test a new shale innovation capable of improving gas production and recoverable reserves by decreasing bottom hole flowing pressure and causing higher reservoir drawdown.

Upwing is a spin-off from Calnetix Technologies, a company that develops and manufactures high-speed motors, magnetic bearings and power electronics. Working with Riverside Petroleum, Upwing completed a trial of its subsurface compressor system. The trial showed a 62 percent increase in gas production and a 50 percent increase in liquid production over a steady state system previously installed with a rod pump.

“Upwing has the technology and system-level integration capabilities to not only make a step change in the reliability and economic feasibility of downhole artificial lift systems, but also to recover significantly more gas and liquids from reservoirs than has been possible previously,” said Herman Artinian, President and CEO of Upwing Energy. “We greatly value our partnership with Riverside Petroleum. In addition to providing us with a trial well, they have been extremely supportive throughout the evaluation, deployment and trial process.”

According to the company, The SCS carries

 

liquids to the surface by creating higher gas velocities throughout the vertical and horizontal wellbores and prevents vapor condensation by increasing the temperature of the gas when exiting the compressor.

More takeaways from the field trial:

This was the first time a system comprised of a high-speed permanent magnet motor, magnetic coupling, passive magnetic bearings with electronic dampers and sensorless high-frequency controls has been deployed successfully in the downhole environment.

Upwing’s SCS was deployed in an unconventional well with a 2,000-foot vertical wellbore and a 5,000-foot horizontal wellbore, where liquid had accumulated. The compressor was installed at the bottom of the vertical section with a tail pipe extending approximately 1,000 feet into the horizontal to provide enough velocity to carry liquids while minimizing friction losses. The installation was very similar to electric submersible pump (ESP) systems in that the SCS unit was tubing deployed, and the electrical cable with the instrumentation was secured around the tubing. The trial period started at the end of October, and the SCS was pulled out in early December.

When the SCS operated at 30,000 RPM, the gas velocity increased to 29 feet per second, and a high rate of liquid was carried to the surface. The hybrid axial compressor was able to atomize the liquid into a very fine mist, which together with the increased velocity and heat generated from the exit of the compressor helped carry the liquids to the surface. The compressor blades showed no sign of degradation despite moving a significant amount of liquids.

 

[ceo_energemsier + 1,818]

Permian satellite system to help predict new oilfield activity

 

Sourcewater Inc. has announced DirtWork Alert, a patented oilfield satellite intelligence service. DirtWork Alert enables Sourcewater clients to see new Permian Basin oilfield development on the ground as soon as it happens, predicting new drilling months ahead of permit filings or rig movements. The online service also identifies probable lease operators and provides geospatial energy data such as land ownership, wellbores, pipelines, permits, rigs, completions, and production of oil, gas and water.

 

"DirtWork Alert is the next generation of energy intelligence,” said Sourcewater Founding CEO Josh Adler. “Every other service shows you what happened in the past, dredging up unreliable regulatory data and serving it past expiration. Our studies show that drilling permits often come out after the wells were already drilled, or for wells that are never drilled. Most well pads and frac ponds are built months before drilling permits are filed, and construction on the ground is a better indicator of intent to drill than a permit because it represents real work for real dollars.”

According to the company, satellite imaging technology identifies real-world activity on a near-daily basis and reports it instantly, so that its clients see opportunities and competition in their areas of interest ahead of the rest of the market. “We often see sitework starting six months before a permit or spud. This is only possible because of advances in computer vision, satellite imagery, artificial intelligence and machine learning. You would need 150 people working 24/7 to cover the 100,000 square-mile Permian Basin at our cadence without our patented AI-enabled methods,” Josh Adler said.

[Douglas Buckland + 6,308]

Of course, the pad construction crews and the dirtwork people would not know about this long before a satellite took a picture of the actual work, you know, when somebody asked for a quote and specified the pad (rig specific) to be built. 
This info would be in the public domain at Billy Bob’s BBQ Pit the Friday after the RFQ was issued...

[ceo_energemsier + 1,818]

Texas Official Unveils Flaring Criterion

 

 

 

An official with the Railroad Commission of Texas (RRC), which oversees various oil and gas industry activities in the state, on Tuesday unveiled what reportedly is a new criterion for gas flaring.

“I calculated the relationship between oil production and flaring, and identified that metric as Flaring Intensity,” RRC Commissioner Ryan Sitton commented in the executive summary to his report on flaring for the first quarter of 2020. “By measuring the flaring intensity of nations, states and various companies, and comparing them all to the global industry average, we now have an effective benchmark to compare performance.”

Some conclusions in Sitton’s report, presented via links to graphs from the document, include:

• Flaring has increased significantly overall in Texas during the past decade, paralleling the state’s oil production levels.
• The estimated range of 650,000 thousand cubic feet per day (Mcf/d) of total flare volumes for Texas oil and gas operators in 2018 ranks among the highest levels on record.
• Among the world’s top oil-producing regions for 2018, the United States and Texas’ respective flaring intensity values fall below the international average.

Cautioning that no remedy should be pursued without considering broader economic and environmental impacts, Sitton’s report also cites the following as some potential options for reducing flaring:

• Waiting for new infrastructure
• Shutting-in the highest-flaring-intensity oil wells
• OPEC and oil buyers – particularly China and India – further restricting and placing flaring requirements on Iraqi and Iranian oil production
• The RRC setting a regulation requiring operators to meet a benchmark for flaring intensity or percent of production flared (PPF).

Sitton also welcomed a public review of the report, urging all interested parties to provide feedback. At least two such industry stakeholders wasted no time in responding Tuesday.

“The Texas oil and natural gas community believes more data is necessary to ensure sound policies and science guide decisions about operations,” Texas Oil & Gas Association (TXOGA) President Todd Staples stated following the release of the RRC flaring report. “While this report points out that Texas’ flaring intensity is already among the lowest rates in the world, industry in Texas is working collaboratively to identify ways to minimize flaring and reduce intensity levels even further.”

Staples also noted that a key component of a flaring-reduction strategy will be adding pipeline capacity to handle existing production and new future output.

“Opposition to safe, clean and secure energy infrastructure like pipelines only serves to weaken Texas and, as the report points out, could hamper efforts to reduce flaring,” remarked Staples. “No one is investing more and working harder than the Texas oil and natural gas industry to find solutions to reduce our environmental footprint while ensuring a stronger energy future here and around the globe.”

Ed Longanecker, president of the Texas Independent Producers & Royalty Owners Association (TIPRO), echoed Staples’ sentiment that more infrastructure would help to mitigate flaring.

“The increase in flaring is due in large part to a lack of adequate infrastructure with wells producing higher levels of associated gas with no access to the systems required to capture that gas,” Longanecker said in a TIPRO written statement emailed to Rigzone. “As outlined in the report from Commissioner Sitton, while Texas flaring volumes are at a high for recent history, current levels are not unprecedented. And though Texas’ flaring intensity has trended up since the 1980s, the state as a whole is still well below historical levels and most of the world.”

Longanecker also noted that additional data and analysis on flaring are welcome, along with “constructive conversations and collaborations” among stakeholders.

“In Texas, over 95 percent of natural gas is captured in gathering systems and transported by pipeline to processing facilities,” Longanecker continued. “We can expect a decrease in flaring volume and intensity as additional pipeline capacity comes online, coupled with a reduction in drilling activity related to capital constraints and other market challenges. As stated in the report, with flaring levels in Texas already lower than most of the world’s oil and gas producing countries, and lower than historical levels, forcing a reduction could actually cause an increase in flaring overseas, while having a negative impact on domestic energy development and the tremendous economic benefit the industry provides at the state and national level.”

The RRC website provides access to the full report and underlying data.

[Coffeeguyzz + 454]

Don't know if this following info is 'shale technology' specific, but it seems to fit into the overall arena of interest ...

Next several weeks, companies will be unveiling their quarterly investor presentations, commonly referred to as the 'dog and pony' shows.

While some commentators on these threads cavalierly denigrate these affairs, they invariably contain an enormous amount of highly relevant, current information, especially if the accompanying q&a sessions are skillfully conducted.

 

To that end, Marathon just released some data of note ...

4 well Bingo pad in the Bakken averaged $4.3 million per to D&C.

Along with setback and unitization changes, these wells will have increased contact with the hydrocarbon-bearing rock.

Pilot well in the Louisiana Austin Chalk had Flowing Casing Pressure over 8,000 with 1,200 bbld of API 49 on restricted choke.

Eagle Ford EOR continues with unpublicised results claiming to be exceeding models.

Their use of huff 'n puff with miscible gas mechanics portends for enormous ramifications across all shale plays as the vast underground infrastructure being emplaced offers intriguing possibilities.

The specific mention of the 'black oil' window in the EF being especially prone to uplift in production brings to mind the enormous potential of the Clinton Sandstone underlying 1/3 of Ohio.

Should practical/economic methods evolve in recovering these vast, shallow, insufficient-pressure resources  ... well, you all know what that means.