SHALE MAGIC: Let the oil flow: US to lead oil output growth through 2030: ConocoPhillips chief economist

US to lead oil output growth through 2030: ConocoPhillips chief economist

 

Global oil demand expected to rise modestly to 2030

Refining capacity will adapt to lighter US crudes

US crude export constraints seen as temporary

 

The US will lead global oil production growth for the next decade, and tight oil can continue to grow beyond the 2030s even moderate prices, ConocoPhillips chief economist Helen Currie told S&P Global Platts Tuesday.

ConocoPhillips expects OPEC net production growth of 2 million-3 million b/d during the next decade, while non-US/non-OPEC oil output will remain "a very big part of meeting the world's energy needs" during that period, she said.

"We find plenty of projects that can be developed at a moderate price level," Currie said of the global supply outlook through 2030.

ConocoPhillips expects modest global oil demand growth through the next decade.

US crude exports will keep rising as domestic production grows. They may face constraints at various times as Gulf Coast infrastructure is getting built, "but we don't foresee those being permanent issues," Currie said. "There are plenty of projects along the Gulf Coast."

While some analysts have questioned whether global refining demand can support the growth in US light crude being projected, Currie said she sees growing domestic demand in the form of announced expansions by Gulf Coast refineries and petrochemical plants.

"We are seeing signs of growth in refining and processing capability in the US for the lighter ends," she said.

ConocoPhillips also expects higher demand for US condensates and NGLs from buyers in Europe, Latin America and Asia.

"We think that will continue to grow. ... There's definitely appetite for light US molecules in the Asia market," she said.

Currie shared a more detailed oil market outlook Monday at the Center for Strategic and International Studies during a briefing held under Chatham House rules. She released some of the findings to Platts Tuesday.

  • Great Response! 1
  • Upvote 1

Share this post


Link to post
Share on other sites

Shale ,  Another Decade of U.S. Supply Growth

(Bloomberg) -- The U.S. will account for almost a quarter of global oil and gas production by the early 2030s as the shale boom keeps on booming, according to the head of Rystad Energy.

Output from shale including crude oil, condensate and natural gas liquids could climb to as high as 25 million barrels a day, Jarand Rystad, chief executive officer of the research and intelligence company, said in an interview in Kuala Lumpur. The U.S. will likely make up about 23% of global liquids production and pump 27% of the world’s gas by then, he said.

Part of the reason for the expected growth is that companies are getting better at hydraulic fracturing, the process of pumping a mixture of water and sand into a horizontal well to create millions of tiny cracks in the shale rock that allow oil and gas to flow to the surface. Frackers are using more sand, creating more cracks and boosting the productivity of each well, Rystad said.

“It’s about sand, horsepower and water injection,” he said at the Asia Oil & Gas Conference. “Those three parameters are what’s driving activity levels, and those are three times higher today than they were back in 2014.”

Rystad has been a staunch believer in U.S. shale since early this decade when many analysts and OPEC ministers were unconvinced that a natural gas drilling revolution would translate to a surge in oil output. He recalled being labeled “ridiculously too aggressive” in 2012 when projecting shale crude production would grow fourfold to 4 million barrels a day within four years. The forecast was too low and shale has transformed the nation into the world’s biggest producer.

 

Looking ahead, Rystad’s optimism is also based on a recent study he’s done on the so-called parent-child interference issue, a concern that drilling a new well too close to an older one will reduce pressure in the original and cut output. While the results were mixed, overall the study showed that companies can stack wells more densely, creating enough drilling locations to support 10 to 15 more years of output growth, he said.

The shale surge underscores just how far the U.S. industry has progressed since former President George W. Bush promised to cut imports from the Middle East when he declared in 2006 that the country was “addicted to oil.” Now, said Rystad, the world is so dependent on American production that if fracking were ever banned it would cause a global energy crisis.

“Shale has become a drug that the world is addicted to,” Rystad said . “We cannot live without it. We’d never be able to compensate with OPEC and offshore production.”

 

 

image.thumb.png.d37ab50477c1ca17ed50357703c41c57.png

 

 

 

  • Great Response! 1

Share this post


Link to post
Share on other sites

(edited)

Let the whining begin LOL!!! MORE OIL LESS WHINING!!!

 

image.png.ed7fab558000cc48d8691478330d2fb7.png

 

image.png.a4a09d92f34291f09d5ecfb0281eef68.png

Edited by ceo_energemsier
  • Haha 1
  • Upvote 1

Share this post


Link to post
Share on other sites

Why Rapid Production in Shale Development is a Perk

 

Since the early days of shale oil and gas production, some analysts have expressed alarm about the rapid decline that those wells experience, suggesting either that this will harm shale’s financial viability and/or lead to an early peak and decline in overall production.  But this attitude fails to acknowledge the benefits of producing a resource rapidly.

It is true that it seems inefficient to install capacity that will quickly be underutilized. No one builds a refinery that will see its utilization drop to 20 percent in a few years. But that is the nature of producing fluids; a field can be designed to produce at a constant rate, but only by offsetting the decline in individual well production, whether by enhanced recovery methods and/or additional drilling.

The contrary interpretation of rapid decline is that it represents accelerated production and thus, accelerated revenue accrual. Investment depends on capital and so revenue must be discounted by something roughly akin to the borrowing rate or desired rate of return, usually from 10 to 15 percent per year. In simple terms, money sooner is better than money later, all else being equal.

The first figure shows representative production curves for a conventional oil well, declining at 8 percent per year, and a shale well whose production drops 65 percent in the first year but flattens out thereafter. In each case, the total production (over eleven years) is about one million barrels. 

INSERT TITLE HERE
 

Considering the discounted cash flow, or revenue which is discounted by 12 percent per year from the initial year, the difference becomes a bit more clear. The second figure shows the discounted revenue for the same wells from 2019 to 2030. The shale well’s front-loading of revenue is clear and financially valuable; total net present value is $36 million versus $29 million for the conventional well in this example.   

INSERT TITLE HERE
 

There is another, somewhat speculative, benefit that shale producers are better positioned to exploit: the impact of supply disruptions. Although all commodities suffer from volatile prices usually due to influences that are not predictable in the medium term, like severe or beneficial weather, the oil industry is particularly prone to fluctuations that persist for a time.  As the figure below shows, the Arab Spring in 2011 disrupted Libyan production and tighter sanctions on Iran in 2012 caused its production to drop. While there were offsetting factors, incidents such as this increase the probability that prices will be elevated for a period of several years.

INSERT TITLE HERE
 

In such cases, being able to bring shale wells on-line and produce a large portion of reserves in 18-24 months can greatly increase the payout for a producer. Instability in a case like Libya’s can be expected to persist for the near-term future, but beyond that, the uncertainty grows. A deepwater platform that takes years to develop and extracts its reserves more slowly is at the whims of the market.

Naturally, there are many other factors that drive oil price cycles in the short-, medium- and long-term, but the accelerated production of shale wells leaves them uniquely positioned to take advantage of the peaks—and hopefully plateaus—in prices that occur from time to time, particularly when they are driven by effects that appear lasting, as with the Arab Spring. 

Overall, then, it is time for pundits to cease decrying the rapid decline in production from shale wells as a curse and recognize it as valuable.

 

 

Contributor

 

 

Michael Lynch

I analyze petroleum economics and energy policy.

I spent nearly 30 years at MIT as a student and then researcher at the Energy Laboratory and Center for International Studies. I then spent several years at what is now IHS Global Insight and was chief energy economist. Currently, I am president of Strategic Energy and Economic Research, Inc., and I lecture MBA students at Vienna University. I've been president of the US Association for Energy Economics, I serve on the editorial boards of three publications, and I've had my writing translated into six languages. My book, "The Peak Oil Scare and the Coming Oil Flood" was just published by Praeger.

https://www.forbes.com/sites/michaellynch/#593f4a8421a1

  • Upvote 1

Share this post


Link to post
Share on other sites

A History Of Shale Pessimism: "Always With You It Cannot Be Done"

Recent reports about bankers’ demands that shale producers not increase upstream expenditure have caused some to be pessimistic about the outlook for shale production, up to and including last month’s “Shale Boom about to go Bust.”   Other stories have emphasized the poor financial performance of the sector, such as “A Gusher of Red Ink,” suggesting that shale is generally unprofitable and urging caution on investors.

 (Of course, as Robert Rapier points out, some appear to be using an incorrect measure of free cash flow by not treating depreciation and amortization as historical, not current, costs.)

Although there have been projections for shale supply that proved too rosy, the media attention often focuses on challenges facing the industry, implying bearish expectations.  Such pessimism is not new: it began with the initial skepticism about George Mitchell’s pioneering efforts to extract gas from shale and continued with an insistence that only gas from the Barnett shale would prove viable.  When other gas shales proved economical to produce, many insisted that oil molecules, being larger, would not flow through fracked shales.  When Bakken oil production proved successful, that success was attributed to the layer of dolomite which most other shales did not possess; when the Eagle Ford proved successful, it was said in 2013 that “each play is in effect its own ‘resource pyramid,’ characterized by a few small ‘sweet spots’.

 

 

Surging production from those and newer shales, notably the Permian, STACK and SCOOP, saw new concerns:  the rapid decline rate of shale wells would severely limit the supply available.   As one recent story put it, “The shale industry faces an uncertain future as drillers try to outrun the treadmill of precipitous well declines.”

This is similar to arguments long made by peak oil advocates: “a whole new Saudi Arabia [will have to be found and developed] every couple of years’’ to satisfy current demand forecasts.”  (Robert Hirsch, quoting Saddad al-Husseini 2005)  Unfortunately, he appeared not to notice the near-identical comment from Jimmy Carter in 1977:  “…just to stay even we need the production of a new Texas every year, an Alaskan North Slope every nine months, or a new Saudi Arabia every three years. Obviously, this cannot continue.”

YOU MAY ALSO LIKE

 
 
 

Now, the arguments are focused on the supposed failure of shale producers to turn a profit.  “In the early stages of the fracking boom, investors tolerated negative cash flows from oil and gas producers, believing that the industry would eventually learn to produce cash as well as oil and natural gas. But most frackers never turned the corner. A few companies can now eke out modest positive cash flows, but the sector as a whole consistently fails to produce enough cash to satisfy its voracious appetite for capital.”

Again, this is not new. A 2011 story in the New York Times said “Money is pouring in” from investors even though shale gas is “inherently unprofitable,” an analyst from ... an investment company, wrote to a contractor in a February e-mail. “Reminds you of dot-coms.”  (The Times Public Editor subsequently suggested the article relied too much on the views of a few pessimists and inadequately explained that the story referred not to the industry as a whole, but to particularly aggressive independents.)

On the analytical side, many of these reports suffer from simplistic views, including a failure to recognize the dynamic nature of production methods.  The breakeven price in most if not all shales today is much lower than a decade ago.  Additionally, the massive losses that occurred when oil prices dropped in 2015 explain a lot of the poor performance of the industry when the returns of the past decade are aggregated.

But many of the pessimists appear to simply be biased, for example insisting that, “…no major new field discoveries are expected.”  This before the Permian had been developed.  Or the argument in 2010, when the Marcellus was first being tested, that “The same financial fundamentals that have hurt other shale plays apply to the Marcellus: difficulty identifying core areas, high marginal costs to produce shale gas, poor economics, the play area is so large that a lot more capital will be destroyed than in other shale plays.”

Interestingly, many of the shale pessimists were also active in the peak oil movement, and just as those promoting that idea expressed great certainty about a very uncertain issue, so many shale pessimists have great faith in their pronouncements.  “It takes an enormous leap of faith to see shale oil production rising another 2 mbpd from here, along with several leaps of logic, which the Citigroup report had in abundance.”

The critic bragged about relying on “cold, hard facts” but in fact, shale production has risen by 4 mb/d since then, even after prices dropped below levels said to be necessary to maintain production.  Not bad for a report derided as “amateurish” which made “extremely dubious claims.” (The same pundit trashed myself and others as peak oil denialists a decade ago.)

I once remarked to a peak oil advocate who, describing the many challenges the industry faced, reminded me of Luke Skywalker, who had to be told by Yoda, “Always with you it cannot be done.”  At some point, the pessimists need to explain how the industry has, by their view, defied gravity for well over a decade, continually increasing production as if a dozen pundits had not predicted otherwise (to paraphrase Charles Mackay’s description of the Thames refusal to comply with the London astrologers’ flood warning).

   Hirsch, Robert “The Inevitable Peaking of World Oil Production.”  In:  Bulletin, Atlantic Council of the United States, October 2005.

 

https://www.forbes.com/sites/michaellynch/2019/06/14/a-history-of-shale-pessimism-always-with-you-it-cannot-be-done/#308041206c6e

Share this post


Link to post
Share on other sites

I've already said this last year!!!!   Its the plan.  Read these posts.

I joined Oil Price back in October 2018. My first post was: 

USA to be dominate oil producers  (oct 29,2018)
OPEC is collapsing (Nov 7, 2018)
Quatar out of Opec 2019 (dec 12, 2018)

Watch. By mid 2019 Alaska will come out of no where with exporting US crude. December is the month that www.BLM.gov will be holding sales for land lease drill rights. Plus having Alaska drilling rights finalized by mid 2019 the pipelines will be flowing.

U.S. Approves $3.2B Appalachian Natural Gas Pipeline  (OilPrice Headline 3/1/19)

PDVSA Declares Emergency On Tanker Fleet By Irina Slav - Mar 07, 2019, 9:30 AM CST

So what I am saying is that this the plan destroy the power of OPEC and make USA the oil powerhouse (albeit for a few years).  Look who is drilling in Alaska on Gull Island.  

I have a strong feeling that come the year 2023 there will be a huge environmental catastrophe created in Alaska to dwarf the Exxon Valdez one and blame it on the current sitting President at that time. President Trump will be in office come 2023 and be blamed for it due to the fact that he Executive Ordered drilling rights in USA again back in Jan 2018.  Then the election of 2024 will bring in a change of guard for a Dem controlled government. Rinse and repeat the cycle again. And here we go around on the merry "we" go around again.

 

So my advice is to take the time and look as US oil stocks and find which ones will work for your portfolio.

Share this post


Link to post
Share on other sites

While the media is often focused on how multibillions are being poured into energy transition projects worldwide (usually focusing on solar and wind), global oil and gas is busy wooing financial investors--some of which seem wary to stay linked to hydrocarbon projects. The potential problem will not bet be related to a lack of investments in renewables but the reduced availability of available financing for existing and future oil and gas projects. The influx of cash into U.S. shale oil and gas may be hiding the real situation on the ground, which may be bleaker than we realize.

Conventional oil and gas projects are lacking mainstream finance options it seems, countering the prevailing media reporting about the majors' high-profile multibillions in profits and increased dividends for shareholders. The media reporting about Shell’s decision to handout more than $125 billion to its shareholders during the next couple of years, which has made headlines, is distracting focus from the situation of the majority of the smaller operators and oilfield service companies.

The total oil and gas sector is far from out of the woods, as debts have become a real burden for many companies. When looking at the offshore sector, the situation has become dire. Debts are staggering, while investments in offshore upstream projects have been faltering. The latter has resulted in a severe liquidity crunch, hitting offshore drillers and oilfield services companies. The latter situation has been discussed at a oil and gas conference in Oslo, Norway recently, where offshore bankers painted a dire picture. Hit by high debt levels and low dayrates for vessels and rigs, companies are struggling to refinance operations. At the same time, the current volatility in the oil and gas markets has constrained major investments into offshore developments during the last few years. The only current bright spots are in the Arabian Gulf, the Red Sea and East Mediterranean.

Offshore service companies such as Seadrill, Solstad Offshore and DOF are still worried about the future, as the market's slow recovery has not yet resulted in better financing options. Globally, analysts are not expecting a real improvement before 2021. The main issue for most service companies is debt being too high, which could result in restructuring or even bankruptcy. As Bloomberg reported earlier this month, “the global offshore drilling outlook remains bleak, with contract coverage expected to be below 55 percent for the rest of 2019, amid a net rig supply increase of 54 rigs year-to-date.”

Some companies have been able to get loans lately, but the majority are still hunting for cash. With institutional investors and banks mainly looking at developments in the U.S., it may be time to restructure or re-educate financial advisors too. The future may not revolve around U.S. shale and gas, as investments there are going to be very high risk. At the same time, U.S. operators are already struggling to meet their debt reduction goals. Some relief has come from the OPEC+ oil price strategy, but the debt is still suffocating.

Western capital discipline is now a potential threat. If banks are not willing to provide adequate financing, operators increasingly will have to look for alternative financing options. The latter could also lead to a fire sale of assets or companies to incumbents from other regions. Looking at the current developments in the Middle East, North Africa and Africa, it would not come as a surprise if Arab investment funds or “private” oilfield service companies are going to hunt for opportunities that emerge in the West. Some acquisitions have already have been made, but no major offshore oilfield services companies have been targeted yet. Looking at some of the key names in the space and their financial situations, it doesn’t take a rocket scientist to see the opportunity on the horizon.

 

https://www.rigzone.com/news/offshores_future_constrained_by_cash_problems-26-jun-2019-159161-article/

Share this post


Link to post
Share on other sites

US-led effort to limit IMO 2020 compliance would not cut fuel prices

US refiners, producers say they are ready for IMO 2020

White House reportedly had concerns about price spikes

EIA sees rule boosting Brent crude prices by $2.50/b

 

 

A US-led defection from next year's tougher international marine fuel sulfur standards would be difficult, if not impossible, and would not lead to lower domestic fuel prices, according to a study released Wednesday by a group of US oil and gas producers, refiners, shippers and trade unions.

 

Charles River Associates conducted the study for the Coalition for American Energy Security, which formed to lobby US lawmakers about the benefits of the International Maritime Organization's 0.5% global sulfur cap on marine fuels starting January 1, from the current 3.5%.

"The US is well positioned to support the global shift to lower sulfur marine fuels, both at the refinery and crude production levels," the study said. "Global refiners and shippers have had many years to prepare, and it appears the industries are driving toward a transition with minimal price disruption or fuel availability issues."

In October, the White House was reportedly considering ways to delay the rule on concerns that it would cause retail gasoline and diesel prices to spike in the middle of President Donald Trump's re-election campaign.

The Trump administration cannot likely delay the IMO rule at this point, but the study raises the possibility of a US-led effort to reduce global compliance.

S&P Global Platts Analytics sees the spec changes as the "most disruptive event to hit the refining sector in decades," requiring a major shift in the structure of global bunker fuels and initially displacing about 3 million b/d of HSFO. Analysts expect middle distillates cracks to surge and gasoline cracks to stay firm.

DEMAND FOR LIGHTER CRUDES

The Energy Information Administration expects the IMO rule to boost Brent crude prices by about $2.50/b as a result of higher demand for light sweet crudes. "However, EIA expects broader global crude oil market conditions to have more significant effects on Brent prices than IMO regulations," EIA said in a March report.

EIA sees US retail regular-grade gasoline prices averaging $2.67/gal in the first quarter of 2020 with diesel prices averaging $3.23/gal -- both up from the Q1 2019 averages of $2.36/gal for gasoline and $3.02/gal for diesel, according to the latest Short-Term Energy Outlook.

Rapidan Energy Group expects the IMO rules to "spark upheaval in the distillate market" and "possibly provoke political intervention from the Trump administration," it said in a note earlier this year.

The refiner-commissioned study said the IMO rules benefit countries that produce light sweet crudes, such as the US, while negatively affecting heavy sour producers like Saudi Arabia, Russia, Iraq, Iran, Venezuela and Canada.

"Therefore, the opposite can be said of a move to partial IMO [compliance], as the higher demand for HSFO and lower value of low sulfur fuels lead to a decrease in the value of US crude oil," the study said.

In April, 14 Republican US senators, including those from top oil and refining states Louisiana, Oklahoma and North Dakota, urged Trump to let the marine fuel sulfur standards take effect without interference, arguing that US refiners and the US trade balance both stand to benefit.

"Any attempt by the United States to reverse course on IMO 2020 could create market uncertainty, cause harm to the US energy industry, and potentially backfire on consumers," the senators said.

Share this post


Link to post
Share on other sites

11 hours ago, ceo_energemsier said:

US to lead oil output growth through 2030: ConocoPhillips chief economist

 

Global oil demand expected to rise modestly to 2030

Refining capacity will adapt to lighter US crudes

US crude export constraints seen as temporary

 

The US will lead global oil production growth for the next decade, and tight oil can continue to grow beyond the 2030s even moderate prices, ConocoPhillips chief economist Helen Currie told S&P Global Platts Tuesday.

ConocoPhillips expects OPEC net production growth of 2 million-3 million b/d during the next decade, while non-US/non-OPEC oil output will remain "a very big part of meeting the world's energy needs" during that period, she said.

"We find plenty of projects that can be developed at a moderate price level," Currie said of the global supply outlook through 2030.

ConocoPhillips expects modest global oil demand growth through the next decade.

US crude exports will keep rising as domestic production grows. They may face constraints at various times as Gulf Coast infrastructure is getting built, "but we don't foresee those being permanent issues," Currie said. "There are plenty of projects along the Gulf Coast."

While some analysts have questioned whether global refining demand can support the growth in US light crude being projected, Currie said she sees growing domestic demand in the form of announced expansions by Gulf Coast refineries and petrochemical plants.

"We are seeing signs of growth in refining and processing capability in the US for the lighter ends," she said.

ConocoPhillips also expects higher demand for US condensates and NGLs from buyers in Europe, Latin America and Asia.

"We think that will continue to grow. ... There's definitely appetite for light US molecules in the Asia market," she said.

Currie shared a more detailed oil market outlook Monday at the Center for Strategic and International Studies during a briefing held under Chatham House rules. She released some of the findings to Platts Tuesday.

The geopolitical ramifications of this need to be fully analyzed by those with the most education and knowledge in this area. This will exacerbate the economic problems of all those nations who are overly reliant on oil profits. We need to look ahead to how this will affect future events and foreign alignments. 

Share this post


Link to post
Share on other sites

2 minutes ago, ronwagn said:

The geopolitical ramifications of this need to be fully analyzed by those with the most education and knowledge in this area. This will exacerbate the economic problems of all those nations who are overly reliant on oil profits. We need to look ahead to how this will affect future events and foreign alignments. 

It has already happened, we are importing minimal barrels from the Mid-East and Venezuela and West Africa.

There is enough market demand to absorb all types of crude oils and hydrocarbons streams globally. Just add the total value of USD$ we have saved over the years of the shale production in not buying and paying for oil to these countries and thereby reducing their monetary and geopolitical influence globally and the help in balancing and reducing the trade deficit and the revenue generated and taxes paid on the exports of crude oi, condensates, and petroleum products, NGLs, LNG

  • Upvote 2

Share this post


Link to post
Share on other sites

4 minutes ago, ceo_energemsier said:

It has already happened, we are importing minimal barrels from the Mid-East and Venezuela and West Africa.

There is enough market demand to absorb all types of crude oils and hydrocarbons streams globally. Just add the total value of USD$ we have saved over the years of the shale production in not buying and paying for oil to these countries and thereby reducing their monetary and geopolitical influence globally and the help in balancing and reducing the trade deficit and the revenue generated and taxes paid on the exports of crude oi, condensates, and petroleum products, NGLs, LNG

I think Russia, Iran, and Saudi Arabia are under the most economic stress so far. I fear that Russia and Iran may start a war of desperation to try to shake things up. They are pushing their limits right now. I am not sure we are wise in blocking so much Iranian oil. 

Share this post


Link to post
Share on other sites

Just now, ronwagn said:

I think Russia, Iran, and Saudi Arabia are under the most economic stress so far. I fear that Russia and Iran may start a war of desperation to try to shake things up. They are pushing their limits right now. I am not sure we are wise in blocking so much Iranian oil. 

It couldnt have happened to a nicer bunch of people (State actor, officials). There is plenty of discontent in Iran amongst the population against the State, but they really cant do anything.

Russia will plod along even though they are hurting as well financially and therefore probably not able to and wont want to "over reach" or create havoc in their support of Iran.

  • Like 1
  • Upvote 1

Share this post


Link to post
Share on other sites

I hope you are right but Russia just moored a destroyer in Cuba with the excuse that we are arming Eastern Europe. Russia, China, and Cuba also have forces in Venezuela. I think our policy is to bleed them dry by making their efforts as costly as possible. 

Share this post


Link to post
Share on other sites

11 hours ago, ceo_energemsier said:

Let the whining begin LOL!!! MORE OIL LESS WHINING!!!

 

image.png.ed7fab558000cc48d8691478330d2fb7.png

 

image.png.a4a09d92f34291f09d5ecfb0281eef68.png

Are you tired of WINNING yet?

  • Upvote 1

Share this post


Link to post
Share on other sites

1 minute ago, ronwagn said:

I hope you are right but Russia just moored a destroyer in Cuba with the excuse that we are arming Eastern Europe. Russia, China, and Cuba also have forces in Venezuela. I think our policy is to bleed them dry by making their efforts as costly as possible. 

Venezuelan dictatorship is on its death bed, their oil industry the main provider of cash and all funds to support the regimes (past and current) is a skeleton of what it was. There is basically no more $$$$ left for them to use for all their hype and buying influence.

Russia knows they cant do much with the sanctions, they are there to secure their interests , the hundreds of billions of $$$ they advanced to Hugo and Maduro over the years with oil as the collateral. They want to make sure they are able to secure their $$$$ with whatever gov comes in next and how to salvage and save face given the circumstances. Without Venezuelan Petro-Dollars Cuba is nothing as well.

Sanctions etc crippling everyone but the Cuban population have lived through it before and they will now again , however the chipping away at the regimes is weakening them. Russia sends their "big ship" for psych ops and optics , so that Maduro and Cuba just dont fold so fast and buys them time to figure out how to secure their own Russian positions for the future.

  • Upvote 1

Share this post


Link to post
Share on other sites

12 minutes ago, ronwagn said:

Are you tired of WINNING yet?

Winning!!!!!

 

d980aa206a232fb92a36967a6c1a8530.jpg

mail9.jpg

MaxthonSnap20190120210043.jpg

  • Haha 1

Share this post


Link to post
Share on other sites

9 hours ago, ceo_energemsier said:

Why Rapid Production in Shale Development is a Perk

 

Since the early days of shale oil and gas production, some analysts have expressed alarm about the rapid decline that those wells experience, suggesting either that this will harm shale’s financial viability and/or lead to an early peak and decline in overall production.  But this attitude fails to acknowledge the benefits of producing a resource rapidly.

It is true that it seems inefficient to install capacity that will quickly be underutilized. No one builds a refinery that will see its utilization drop to 20 percent in a few years. But that is the nature of producing fluids; a field can be designed to produce at a constant rate, but only by offsetting the decline in individual well production, whether by enhanced recovery methods and/or additional drilling.

The contrary interpretation of rapid decline is that it represents accelerated production and thus, accelerated revenue accrual. Investment depends on capital and so revenue must be discounted by something roughly akin to the borrowing rate or desired rate of return, usually from 10 to 15 percent per year. In simple terms, money sooner is better than money later, all else being equal.

The first figure shows representative production curves for a conventional oil well, declining at 8 percent per year, and a shale well whose production drops 65 percent in the first year but flattens out thereafter. In each case, the total production (over eleven years) is about one million barrels. 

INSERT TITLE HERE
 

Considering the discounted cash flow, or revenue which is discounted by 12 percent per year from the initial year, the difference becomes a bit more clear. The second figure shows the discounted revenue for the same wells from 2019 to 2030. The shale well’s front-loading of revenue is clear and financially valuable; total net present value is $36 million versus $29 million for the conventional well in this example.   

INSERT TITLE HERE
 

There is another, somewhat speculative, benefit that shale producers are better positioned to exploit: the impact of supply disruptions. Although all commodities suffer from volatile prices usually due to influences that are not predictable in the medium term, like severe or beneficial weather, the oil industry is particularly prone to fluctuations that persist for a time.  As the figure below shows, the Arab Spring in 2011 disrupted Libyan production and tighter sanctions on Iran in 2012 caused its production to drop. While there were offsetting factors, incidents such as this increase the probability that prices will be elevated for a period of several years.

INSERT TITLE HERE
 

In such cases, being able to bring shale wells on-line and produce a large portion of reserves in 18-24 months can greatly increase the payout for a producer. Instability in a case like Libya’s can be expected to persist for the near-term future, but beyond that, the uncertainty grows. A deepwater platform that takes years to develop and extracts its reserves more slowly is at the whims of the market.

Naturally, there are many other factors that drive oil price cycles in the short-, medium- and long-term, but the accelerated production of shale wells leaves them uniquely positioned to take advantage of the peaks—and hopefully plateaus—in prices that occur from time to time, particularly when they are driven by effects that appear lasting, as with the Arab Spring. 

Overall, then, it is time for pundits to cease decrying the rapid decline in production from shale wells as a curse and recognize it as valuable.

 

 

Contributor

 

 

Michael Lynch

I analyze petroleum economics and energy policy.

I spent nearly 30 years at MIT as a student and then researcher at the Energy Laboratory and Center for International Studies. I then spent several years at what is now IHS Global Insight and was chief energy economist. Currently, I am president of Strategic Energy and Economic Research, Inc., and I lecture MBA students at Vienna University. I've been president of the US Association for Energy Economics, I serve on the editorial boards of three publications, and I've had my writing translated into six languages. My book, "The Peak Oil Scare and the Coming Oil Flood" was just published by Praeger.

https://www.forbes.com/sites/michaellynch/#593f4a8421a1

No self esteem problems with Michael Lynch. 

  • Haha 1
  • Upvote 1

Share this post


Link to post
Share on other sites

13 minutes ago, ronwagn said:

No self esteem problems with Michael Lynch. 

You are into LNG data, here is some tidbit

 

Gasum’s liquefied natural gas (LNG) bunker vessel, Coralius, made its first bunkering in the port and refining area of Rotterdam, supplying LNG to Bit Viking.

The vessel that mainly operates in the North Sea and the Skagerrak area completed its 100th bunkering operation during the end of February.

Speaking of the bunkering in Rotterdam, Kimmo Rahkamo, vice president, natural gas and LNG, Gasum, said, “finally, being able to bunker our clients in the ARA area increases LNG availability and security for the LNG fueled fleet.”

Coralius delivers LNG through ship-to-ship bunkering at sea and in port. This has significantly increased Gasum’s flexibility and responsiveness to vessels that require LNG but are unable to visit a terminal or a port. By making LNG more accessible to vessels, ship-to-ship bunkering also boosts efficiency.

Anders Hermansson, technical manager of Tarbit Shipping said that the Bit Viking has been converted to run on LNG in 2011 and has operated using the chilled fuel 97 percent of the time.

Gasum foresees an increase in the average amount of delivered stem, as it will perform bunkerings on shuttle tankers and other bigger vessels.

Coralius has increased its efficiency due to LNG bunkering operations becoming faster – they are now nearly as quick as conventional oil bunkerings, Gasum added.

  • Upvote 1

Share this post


Link to post
Share on other sites

Doesn't this shale miracle actually depend on 'how long it's legs are'? The LTO proponents keep saying we'll be here in the future or oil shale will be doing that in the future, as if they have a crystal ball.

What about the issues they are facing in the 'here and now'? Debt, falling rig count, flaring, etc...

Regardless who owns the lease, the decline curves remain alarming, the sibling well issue remains in play, the fluid dynamics and rock properties do not change, the number of 'sweet spots' continues to decline and so forth.

I would think that all of this suggests that the tight oil horse may have shorter legs than the riders would like you to believe.

  • Great Response! 1
  • Upvote 1

Share this post


Link to post
Share on other sites

21 hours ago, Douglas Buckland said:

Doesn't this shale miracle actually depend on 'how long it's legs are'? The LTO proponents keep saying we'll be here in the future or oil shale will be doing that in the future, as if they have a crystal ball.

What about the issues they are facing in the 'here and now'? Debt, falling rig count, flaring, etc...

Regardless who owns the lease, the decline curves remain alarming, the sibling well issue remains in play, the fluid dynamics and rock properties do not change, the number of 'sweet spots' continues to decline and so forth.

I would think that all of this suggests that the tight oil horse may have shorter legs than the riders would like you to believe.

Oil prices depend on demand and relative scarcity. Shale has eliminated scarcity of oil for now. This is nothing new, it is why the Texas Railroad Commission started its price fixing policies. They would not be allowed to do that today. 

Share this post


Link to post
Share on other sites

This year, the U.S. will surpass Malaysia to become the world’s third largest seller of LNG. The country could even eclipse Qatar and Australia to take the top spot by 2024. This is truly staggering growth considering that LNG exports from the contiguous 48 just began in February 2016, when Cheniere Energy’s flagship Sabine Pass terminal in Louisiana first came online.

U.S. LNG has thus far reached over 30 nations, with South Korea, Mexico, Japan, and China receiving the most. By the end of 2019, the U.S. will have doubled its export facilities to six. And the country will have expanded its capacity to ~9 Bcf/d, more than 20 percent of current LNG demand. Although China has now put a 25 percent tariff on U.S. LNG, the expectation is that the trade war will eventually be worked out, reopening the door to the world’s most vital incremental customer.

For LNG buyers, the U.S. is a highly desirable partner. The country has soaring domestic gas production (up 60 percent since 2008), a massive low-cost resource base, flexible contracts, and a hub-based pricing system that reflects the transparency of supply and demand. IHS experts, for instance, estimate that the U.S. has 700 Tcf of gas that can be produced even when prices are below $3 per MMBtu. The EIA expects annual U.S. output to grow non-stop at 1-2 percent for decades to come, double the domestic consumption rate.

U.S. LNG is expanding the short-term, spot market, now accounting for just 30 percent of global trade. This is helping to increase flexibility and liquidity in the market, importantly giving the less wealthy nations a better chance to participate. While it still represents just 12-14 percent of global gas usage, LNG is the fastest growing traded commodity. Trade has been rising 8-10 percent per year in recent years and growth will remain in the 4-7 percent range for as far out as current modeling goes.  

As for U.S. gas users, LNG exports are a bullish factor and will put a floor under domestic prices. However, numerous studies indicate that a coming U.S. LNG export surge of 15-20 Bcf/d would likely only increase domestic prices 10-15 percent in the mid-term, and perhaps even less in the long-term. Exports will actually keep price increases in check because they beget more gas production. 

The comparison that some U.S. industrial groups make to Australia, where an LNG export boom led to domestic gas shortages and spiked prices, is a faulty one. Australia has been exporting over 60 percent of its production, while the U.S. should top out at below 20 percent. Australia has also crippled itself with bad policy, such as exploration and fracking bans. Ultimately, if U.S. LNG exports do increase domestic prices too much, they will simply limit themselves by pushing buyers to look for cheaper sellers. The U.S. also has a “protect the public interest” clause where the federal government can limit outside sales if deemed necessary.  

Nevertheless, the U.S. government and domestic gas users must constantly monitor developments. With so much LNG exports coming online, pioneer Cheniere says that Henry Hub-based contracts could account for ~35 percent of global LNG by 2025. In short, LNG exports will increasingly bring competition for American buyers and tie the U.S. to the more precarious globalizing market.  

To be sure, U.S. LNG faces substantial competition. While the Trump administration has been advertising to buyers in Europe, Russia says that its piped gas will remain at least 30 percent cheaper. And Gazprom has been surprisingly willing to renegotiate contracts to remain Europe’s primary supplier. Lowering transport costs, Australia is much closer to fast-growing Asia than the U.S., and Qatar is rapidly expanding its export capacity to retain its top ranking. Other emerging competition for U.S. LNG is Canada, Mozambique, European re-sellers, and giant commodity trading houses with wide international links.

Yet, the potential for all LNG sellers is great. Natural gas is increasingly the go-to fuel for nations to grow their economies, lower greenhouse gas emissions, and backup intermittent wind and solar power. In a carbon-constrained world, it is cleaner and more flexible natural gas that will continue to win out.

Share this post


Link to post
Share on other sites

The Exit Of U.S. Giant ExxonMobil Highlights The Decline Of North Sea Oil And Gas

It seems that the U.S. exodus of the Norwegian Continental Shelf (NCS) is now in full swing. Following hot on the heels of the decision by Chevron last year to exit the region, the news is coming out of Houston that the largest U.S. energy company, ExxonMobil, is planning to sell its Norwegian assets. Although they are no longer an operator in the region, the U.S. giant holds stakes in around 20 operating fields and projects in the area.

A continuing trend

Despite this being the most significant transaction on the NCS for a decade, Julien Mathonniere, global crude oil deputy editor at ICIS does not believe this deal will have a substantial impact on the region. "ExxonMobil sold its operated oil and gas assets in Norway two years ago and no longer is an active player in the Norwegian North Sea" he explained. "We're only talking of the remaining, non-operated Norwegian Continental Shelf assets here, which are sizeable but not huge. Norway's national oil company (NOC) Equinor already operates most of these fields."

Daniel Rogers, oil and gas analyst at GlobalData, agreed that the move will have little impact. "ExxonMobil's position in Norway has been dwindling over the recent years; the company offloaded all of its operated assets in the country in 2017 but still retains stakes in 19 producing fields," he said. “Norwegian production only accounts for approximately 3% of the company's total portfolio, and the sale could help focus on activities in more core growth regions such as onshore U.S. and deep-water South America."

 

 

Looking for low-cost oil

The strategy behind the decision is simple: oil economics are shifting to more profitable plays and areas for integrated oil companies like ExxonMobil. "The tentative merger between Chevron and Anadarko earlier this year has signaled a change of paradigm among majors, some of which are refocusing on the more profitable U.S. shale plays and LNG projects," Mathonniere added. "ExxonMobil is the largest U.S. oil and gas company, so if its competitor Chevron has identified profitable opportunities in U.S. shale and LNG, then I'm inclined to think that ExxonMobil will follow through in some way, especially since those opportunities are low-hanging fruits lying in its backyard."

The age of the independents

ExxonMobil's exit could pave the way for several smaller, independent operators with lower operating costs to enter the arena, in much the same manner as Chrysaor's acquisition of ConocoPhillips UKCS assets for $2.68 billion last year. Norway's Okea, a private equity-backed firm, has also been mentioned as a potential buyer, and independent exploration and production companies like Aker BP, DNO, Lundin Petroleum, and PGNiG could also be among the front runners for a potential bid.

 

 
 
 

"Aker BP and DNO both previously expressed interest for mature NCS assets," Mathonniere continued. "Both are Norwegian. DNO made a hostile and controversial $778.5 million bid for U.K.'s Faroe Petroleum in November 2018, eventually ending with 20% more shares of Faroe, for a total ownership of 30.6%. Aker BP acquired 11 NCS licenses from Total for $205 million in July 2018. Both seem well positioned to continue their asset spree."

Building a balanced portfolio

For potential buyers, the assets would provide a steady positive cash flow and an oil-weighted production portfolio. ExxonMobil's Norwegian production in 2018 averaged 155,000 barrels of oil equivalent per day and has declined year-on-year over the last 11 years due to production declines in major fields such as Statfjord, coupled with the sale of significant assets like Balder.

"With estimated remaining recoverable reserves of approximately 400 million barrels of oil equivalent from producing fields, there is significant value to be captured," Rogers continued. "Growth opportunities include the Trestakk oil field due to commence production in 2019 with expected gross recoverable reserves of 80 mmboe, the Snorre expansion project expected to extend field life beyond 2040 and gas discovery opportunities at Lavrans and Mikkel Sor."

A steady decline for the North Sea

The decision by ExxonMobil to leave the area also highlights the fact that the North Sea is not where the future of oil is. “It's been a declining petroleum province for a while, and it only accelerated after the oil price collapsed in late 2014," Mathonniere concluded. "Activity there has registered a painful decline, particularly concerning field investment expenditures, but also to operating costs.

"Exploration activities are below the levels that would allow renewing reserves. Production is hence not sustainable. The Johann Sverdrup is the latest big discovery on the NCS, but it might also be the last one given the lackluster exploration budgets."

 

https://www.forbes.com/sites/markvenables/2019/06/26/the-exit-of-us-giant-exxonmobil-highlights-the-decline-of-north-sea-oil-and-gas/#6c294f4723b1

 

Share this post


Link to post
Share on other sites

FRAC TECHS

____________________________

 

Higher Demand For Perforating Systems Strains Supply Chain

With increased drilling rig efficiency and longer laterals, the horizontal environment has changed the nature of the perforating business.

 

PERFORATING SYSTEMS INDUSTRY UPDATE:

The zenith of the drilling rig count in the U.S. occurred on Dec. 28, 1981. There were 4,530 rigs in the U.S. drilling about 30,000 to 35,000 mostly vertical wells per year. On April 12, 2019, the rig count was 1,022 rigs. Even at that number, the industry is still drilling 30,000 to 35,000 mostly horizontal wells per year.

“I was a field engineer when I first started my career. I would go out and shoot maybe 10 guns per well. Today in a horizontal environment, we shoot 50 stages. We might shoot 10 guns per stage. We are shooting 500 guns in a well, an order of magnitude higher,” said George Patton, product development manager for the Owen Oil Tools division of Core Laboratories.

“One of the challenges for us is that we have to build more guns, more charges, more detonating cord, more detonators and more switches. For all the technology that has been around for decades, we have to be able to manufacture more than we have ever done in the past. At the same time, we need to be more cost effective.”

That demand for more equipment has led to other challenges. “Just the volume of the business is stretching the supply chain really thin,” said James Barker, Halliburton technical chief for perforating technology. “There are shortages in steel for the gun carriers and even explosive powders for the shaped charges. There have been significant shortages in those arenas over the last year, especially the explosive powders.”

That has led Halliburton to introduce new frac charges based on the explosive pentaerythritol tetranitrate (PETN). “That’s really a polymer-coated PETN for enhanced handling and safety. It was released in 2019,” he said.

The increased efficiency of the drilling rigs and the shift to longer laterals in horizontal wells have impacted perforating systems. “The whole horizontal environment has changed the nature of our business enormously. A lot of the ideas we used to accept in the vertical environment are being challenged in the horizontal environment,” Patton said.

Companies are also beginning to measure the efficiency of perforating systems with defects per million opportunities (DPMO). “The reliability has increased to about 99% or better, but even more is demanded. As the industry gets better and better, you kind of lose whatever 99.x% means from a success standpoint. If you cast it in DPMO, then it amplifies how good you really are,” Barker said.

While the sheer demand for perforating guns is straining the system, manufacturing companies continue to work with operators and service companies to improve the technology for perforating systems.

Consistency of hole size
With the advent of horizontal wells, what has really become a critical factor is the consistency of the hole size. In a horizontal well, the guns will sit on the low side of the casing. The perforation hole size can vary around the casing.

“You have one shot right next to the casing on the bottom of the casing. Then, you have a shot on the top of the casing that is going across the fluid gap between the gun and the casing. The performance of that charge is diminished. It is no longer what the API [American Petroleum Institute] specs are,” Patton said.

Frequently, the hole size consistency can be a 20% standard deviation with a standard conventional charge, he explained. “You might have an average 0.36-in. hole, but in the 6 o’clock position, the hole size could be 0.49 in. and 0.24 in. in the 12 o’clock position. We can change the shape of the jet that makes the perforation so we can get a hole size in all six positions around the casing down to a 3% standard deviation,” he said.

Owen Oil Tools’ consistent-hole-size charge is branded HERO PerFRAC, which is now its largest selling series of charges. This product line was initially introduced in 2014 and relaunched in 2016. Since then, the company has improved the standard deviation from less than 10% to less than 3%.

Owen Oil Tools The hole size consistency can be a 20% standard deviation with a standard conventional charge (right). Owen Oil Tools has improved its standard deviation from less than 10% to less than 3% (left). EH stands for the entrance hole diameter of the casing.
(Source: Owen Oil Tools)

“We have talked to the operating companies about their specific casings because hole size varies for each casing size, weight and grade. The gun sizes may change if you have large or small casing. We’ve brought in clients, and they have given us samples of their casing. We shot those at Owen Oil Tools’ facility in Godley, Texas. We demonstrated what we say about consistent hole size is true. They have used them in their wells and gotten better results, lower frac pressures, fracs being put away and even better production,” Patton said.

Another product being rebranded is the company’s ZERO 180 Perforating System, which is now being called Pinpoint Perforating System. This orients the gun downhole in a horizontal well. Society of Petroleum Engineer papers have documented that an operator should shoot in the 12 o’clock and 6 o’clock positions for the best frac performance.

“We have a tool that orients downhole in a horizontal well so you can shoot in any direction that you want,” Patton said. “We’ve got people who want to shoot in three directions—at 12 o’clock, 10 o’clock and 2 o’clock. That is very client specific.”

Another aspect of the Pinpoint Perforating System is avoiding fiber-optic control lines running down the outside of the casing with costs of about $1 million each on an average horizontal well. You have to be able to determine where the control line is. There are some logging tools and techniques to determine this. Once you know where they are, you can design your guns to shoot away from them,” he said. The company has had success in 2017 and 2018 with several wells in Canada that use control lines.

Wireline-conveyed pump-down technologies
The gun systems for plug-and-perf operations to support hydraulic fracturing in the shale fields are getting better and better, Halliburton’s Barker said. “By that I mean premiums are now placed on things like fast turnaround time, efficiency at the well site and reliability so that you minimize idle time for the frac pumps,” he said.

“Trying to get the DPMO number better just drives you to be better in your gun designs where the parts come together quicker and easier for our field organization to assemble. That has led to our company being one of the pioneers in loaded guns from the manufacturer. We can load guns here in a controlled environment at the shaped-charge plant and ship loaded guns to the districts,” he continued.

For this type of market, the industry is still trying to determine what the optimal perforating design for their frac is. “The trend now seems to be shorter guns with fewer shots per cluster but [to] have more clusters per stage. What might be eight to 12 clusters per stage may now be around 20 clusters. Even as I say the trend is toward shorter guns, we just had some orders come in for longer frac guns with 15 to 18 shots. I think the jury is still out with the production and frac pumping companies themselves,” he said.

The propellant suppliers are getting into the schemes as well by enhancing the perforation with some overpressure from a propellant. “Some of these are now being tried in the field to see if that helps lower breakdown pressures and makes more efficient fracs at the well site,” he said.

Coated PETN does alleviate the safety concerns. There are powder shortages with the traditional explosives that are used every day in the oil and gas industry—RDX (cyclotrimethylene trinitramine) and HMX (cyclotetramethylene tetranitramine).

“PETN, if it is not manufactured properly, can be a more sensitive explosive. Our introduction is a polymer-coating that covers the crystals of the explosive, which brings its sensitivity to the RDX and HMX levels,” Barker said. “What we see is no real clear winner. Maybe there never will be. There is always some wrinkle from field to field or area to area. But there is a broad product offering right now. There seems to be no universal gun system such as the six shots, 60-degree phasing. There are other options.”

Tubing-conveyed perforating, testing
For tubing-conveyed perforating systems, there is a trend toward larger diameter gun systems—the 6½-in. and 7-in. gun systems for offshore work with high shot densities of larger explosive quantities. This technology is still being requested by customers.

“What is new technology is the modeling software for job design because you are looking at two things. When you shoot those big guns, how do you make sure you’ve optimized your production through controlling the dynamic underbalance and other geomechanical considerations of the formation?” Barker asked. “Because of the large explosive contents, you also have to make sure that structurally your guns are protected from collapse and parting, and that you don’t corkscrew the tubing or unseat the packers. There are now quite a few advancements made in the modeling software that predict both what is happening in the reservoir and how you protect your perforating gun string and completion string from damage.”

The last item involves testing that is specifically available in the flow laboratories.

“The industry has known for a long while that it is doing a good job of directing the industry in perforator penetration prediction. API 19B uses concrete targets shot on surface. Folks have now realized that is not really telling the true picture,” he said. “People are now beginning to realize that this also applies to the hole diameter that is produced in the casing. We’re beginning to see now that this is a much more complex mechanism than was envisioned previously when using hole-size predictions about what happens behind the casing based on surface-condition targets. Instead, those shots need to be done under simulated wellbore conditions if you want to have an accurate representation of what is happening.”

Tests at the Halliburton Advanced Perforating Flow Laboratory Tests at the Halliburton Advanced Perforating Flow Laboratory are designed to provide a measure of the flow performance of a perforation into a stressed rock, simulating reservoir-specific downhole conditions. (Source: Halliburton)

Manufacturing challenges
Owen Oil Tools has had to gear up its manufacturing operations and improve the technology in manufacturing, including the techniques the company uses to manufacture because it needs to be more cost effective, Patton said.

“Operating companies are coming to us now wanting us to build thousands of guns instead of tens of guns. They want us to be able to do it cheaper than what we could for tens of guns. We’re automating our manufacturing processes more than we have ever done. We’re using robotics more,” he said. “The whole manufacturing operation is changing dramatically. The demand for Owen products is greater than it has ever been. We sell millions of charges every year and hundreds of miles of guns. We need to be very efficient in services that we provide in perforating for those companies to bring oil and gas to the worldwide community at an effective price.”

One of the manufacturing challenges for Owen Oil Tools is that historically it has not had relationships with the operating companies. “One of the things we’ve been doing the last couple of years is spending more time and talking directly with the operating companies concerning the value that we bring to their operations,” Patton said.

The company does not want to lose its relationship with the service companies that distribute its products to the operators, but they are spending more time with the operating companies. “That was something we didn’t do 20 years ago. But we give them a lot more today by working directly with the operating companies while maintaining relationships with our historical clients,” he said.

Share this post


Link to post
Share on other sites

PERFORATING SYSTEMS TECHNOLOGY SHOWCASE:

Operators are constantly searching for the latest innovations to maximize production. The following technologies are some of the latest products and services available to the industry.

Editor’s note: The copy herein is contributed from service companies and does not reflect the opinions of Hart Energy.

_____________________________________________________________________________________________________

Perforating tool simulates and predicts dynamic conditions
Built on advanced analysis and job planning data, Baker Hughes, a GE company’s (BHGE) TerraConnect perforating technology, engineered for reservoir conditions, simulates and predicts the dynamic conditions that occur during perforating events (See image above). These simulations predict transient behavior during laboratory testing, translating to optimum job designs that improve downhole results and reservoir contact. Using its PulsFrac software, BHGE optimizes perforation tunnel cleanup with a variety of technologies, including TerraFORM dynamic underbalance optimization services, TerraPERM propellant perforating optimization services and static underbalance techniques. The TerraConnect perforating technology and PulsFrac software provide a perforating design and cleanup operations optimized for the target reservoir. TerraConnect was recently applied on a multiwell project in Southeast Asia where laboratory test results led to product and deployment technique selection. Collaboration with the operator led to continual operational and production improvement over the course of the project, contributing to the ultimate reduction of wells planned by 33%. bhge.com

Consistent hole size perforating
Horizontal, unconventional wells have revolutionized the industry and fundamentally changed perforating. Consistent hole size perforating has proven highly successful and has become the standard. As production on unconventional wells declines, operating companies are challenged to revitalize these assets through recompletion or refrac methods. Core Lab/Owen has delivered ReFRAC technology to meet this challenge. Mechanically isolated refrac wells with cemented tubulars inside existing well casing are exponentially more complicated to provide consistent holes due to perforating two strings of casing with cement in between. Fracturing is more difficult, resulting in fewer stages per day and increased costs. ReFRAC charges produce optimal and consistent holes to meet these challenges. Two major operators have seen two to three times the number of stages per day completed with fewer perforations. Costs and time on the well were reduced and profit margins increased. Multiple operators are requesting ReFRAC charge technology in this recompletion application. corelab.com/owen

Core Lab/Owen ReFRAC perforating charges shoot consistent holes through two casing stings. (Source: Core Lab/Owen)

Perforating system shortens gun length
The DynaEnergetics DS Trinity perforating system offers three charges in a single plane (three-in-a-plane) to shorten gun length and provide formation benefits during the hydraulic fracturing process. At less than 8 in. overall length, the new system is up to 3.5 times shorter than conventional perforating guns, enabling much higher gun counts per stage. Shorter gun lengths also save on running costs by reducing the height requirements for rigup cranes and pressure control equipment. The single-plane charge architecture has been determined to reduce formation breakdown pressure and achieve optimal rates quicker, which can ease wear and tear on fracturing equipment. In addition, single-plane perforating can lead to better fracture geometry in certain formations, enhancing overall well productivity. Recently completed field trials were conducted in partnership with a large U.S.-based independent operator that provided feedback on key features and functionality of the system. More than 1,000 guns were delivered during the field trial process, which was conducted with 100% success rate. dynaenergetics.com

DynaEnergetics The DynaEnergetics DS Trinity single-plane perforating system is up to 3.5 times shorter than conventional perforating guns. (Source: DynaEnergetics)

Technology eliminates clogged perforations
Kraken technology is a progressively burning, solid propellant designed to increase penetration, eliminate clogged perforations and overcome near-wellbore damage from compaction caused by traditional perforators. Progressively burning Kraken propellant boosters generate high-pressure gas in the perforation tunnels, which creates fractures that improve well connectivity. Completion engineers who scorecard breakdown pressure, IP/II increase, operating time and safety will observe that the return on incremental investment in enhanced perforating performance routinely exceeds 100%. enhancedenergetics.com

Kraken GasGun A cutaway of the Kraken tool in a well is shown. (Source: Enhanced Energetics)

Interventionless perforating tool requires no electronic detonation
Nine Energy Service’s FlowGun technology is a stage one interventionless casing-conveyed perforating tool that eliminates the need to run wireline or coiled tubing (CT) and requires no electronic detonation. FlowGun offers an innovative, safe and cost-effective advantage for stage one completions. It offers infinite efficiency, control and flexibility. With FlowGun, operators see increased savings on time and money because the numerous downhole jobs are consolidated into one tool and one crew with no sleeves to shift, no wet shoe required and no electronic detonation needed. An entire phase of completion is eliminated, removing the need to pay for additional water, tank trucking BOP rental, CT, chemicals and labor. nineenergyservice.com

Sliding sleeve tool helps operators avoid risks
While it is a very widely used completion method, plug and perf can have a negative effect on near-wellbore permeability, as the impact stress associated with the outward traveling shock of a shaped charge weakens the rock matrix and increases the risk of sand production. The i-Frac system from National Oilwell Varco (NOV) helps operators avoid the risks inherent in using conventional perforating methods with explosive charges and guns. The i-Frac is a hydraulically operating sliding sleeve tool that is threaded in as part of the production casing. Using a ball or a coil-conveyed tool, the sleeve is shifted, and perforations are exposed to the inner casing from inside; on the outside, perforations are covered up with cement. After this, a pressure increase breaks through the cement and initiates communication with the formation. A single stage can contain up to 20 i-Frac sleeves, with one ball dropped to activate all the sleeves and isolate the zone for stimulation treatment. nov.com 

NOV The i-Frac sleeves are ball-drop-activated multistage frac sleeves designed for cemented, multiple open/close and openhole horizontal completions. (Source: NOV)

Perforating gun system increases safety
Schlumberger’s Tempo instrumented docking perforating gun system is the industry’s first perforating gun system to fully integrate a plug-in gun with real-time advanced downhole measurements throughout the operation. This unique combination significantly mitigates operational risk while increasing safety, reliability and efficiency. By generating and confirming dynamic underbalance in the well, the Tempo system effectively removes perforation debris to optimize productivity. First-year deployments include North and South America, the Middle East, Europe and Asia. According to the company, excellent results have been achieved, from understanding the wellbore dynamics during perforation to achieving a 100% fires success rate on all guns deployed without any misfire. In Egypt an operator employed the Tempo system to improve the efficiency of multizone perforating operations in deep wells in the Western Desert. Conventional perforating gun systems had required significant operational time to assemble and arm, and their integrity could not always be verified until at perforating depth, at which point diagnosing any connection failures caused lengthy remedial downtime. The new plug-in gun simplified design saved considerable time, including reducing gun arming time by more than half. slb.com/tempo

Schlumberger Tempo The Tempo system fully integrates a plug-in gun with real-time advanced downhole measurements for monitoring and confirming operations to mitigate risk while increasing safety, reliability and efficiency. (Source: Schlumberger)

Share this post


Link to post
Share on other sites