We have not seen end of Shale or Deepwater technology efficiencies. Its accelerating . EX: Cramer talks to Core Labatories

[Falcon + 222]

Its not just better rigs. Better propants, reservoir mapping, well placement, etc, etc, etc 

As one analyst said this morning, E & P (exploration and production) is a misnomer, "there is no more "E" (exploration) We know where the oil is.  Companies have gone from exploration to Manufacturing."  Size and efficiencies will prevail. 

 

https://www.cnbc.com/video/2019/05/02/core-laboratories-ceo-a-remarkable-boost-in-us-crude-production.html

Edited May 7, 2019 by Falcon

[Douglas Buckland + 6,308]

If that is the case I will not expect to see any exploration or appraisal drilling in the future. It would be pointless and costly if you already know where the oil is, the porosity and permeability of the reservoir, how much the reservoir will deliver, and the fluid properties.

The smart operators will go directly to development drilling.

Just imagine the cost savings and the reduction in lifting costs realized by not requiring exploration and appraisal costs!

[Mike Shellman + 548]

Essentially all of America's shale oil basins are leased, delineated and getting hammered with wells; how long can that last? The choice being made between marginally (un) profitable shale oil development and exploration and/or infill development of existing conventional fields to arrest decline is ultimately going to have dire consequences for America, and the world. It's great now (except the debt, +$18 billion a year interest on that debt and what else? oh yeah, the 84% decline rates the first 30 months of production) but its always a good idea to imagine what the world and America will look like five years from now. Parents tend to worry about that sort of thing.

Service companies have been getting whacked trying to make all these tech "miracles" work for the shale oil industry; how long can that last? Productivity, by the way, is not the same as profitability. I am awaiting 4-5 other earnings reports, several big ones today...the number of shale oil companies that lost money 1Q19 is staggering. In fact, all pure shale players in the Permian, so far, did lose money. 

 

Edited May 6, 2019 by Mike Shellman

[Tom Kirkman + 8,860]

1 hour ago, Mike Shellman said:

Productivity, by the way, is not the same as profitability. I am awaiting 4-5 other earnings reports, several big ones today...the number of shale oil companies that lost money 1Q19 is staggering. In fact, all pure shale players in the Permian, so far, did lose money. 

Nike, do you have any way for others to independently verify your comment above (which I bolded for emphasis) that 

..the number of shale oil companies that lost money 1Q19 is staggering. In fact, all pure shale players in the Permian, so far, did lose money. 

 

I don't really doubt this ^ , but nailing down facts to prove this to naysayers can be a bit difficult.

[Mike Shellman + 548]

15 minutes ago, Tom Kirkman said:

I don't really doubt this ^ , but nailing down facts to prove this to naysayers can be a bit difficult.

Ignore the lipstick being smeared on this stuff, start with Nobel, Apache, Anadarko, Concho, Parsley, QEP, WPX, and Laredo; go to their SEC filings. PXD will likely report a loss this evening, again, and we're awaiting Cimerex, FANG, Energen, Cabot and Callon. Prices were good, costs low and productivity sky high 1Q19; everybody should have hit a lick. They didn't and they'll all have excuses. Does not look to me that anybody deleveraged for the quarter either. Debt costs are choking these guys to death. 

[ceo_energemsier + 1,818]

https://cdn2.hubspot.net/hubfs/1545457/ Upstream/PDFs/OTC 2019 TechSupplement.pdf

[ceo_energemsier + 1,818]

The single biggest mistakes made by some shale companies have been

1) paying extremely high prices for acquiring acreage.

2) Some of those over priced acreage were not worth the paper they were leased on.

3) High costs initially for drilling and completion of wells.

 

As things "normalize" in terms of wide spread lease management and deploying resources to wells that fit in the goemodeling and geotechnical good quality rocks, things will improve.

Have been in the shale E&P since 2005, had issues early ion relying on general common approach to drilling and completing, since witching over to specific needs based on acreage unique challenges and specific drilling completion needs, we havent had that issue.

Technology is the biggest factor and answer to  most issues, the days of vertical wells drilled without apllication of tech and drilling sites come up with on a whim are long gone. Our costs have been for the last several years , down in the range of 25-34$/bbl and 35-42$/bbl and those latter numbers are coming down fast too.

Using a combination of few techs has helped a lot, including but not limited to natural fracture subsurface mapping in combo with 3D and drilling and producing from stacked plays, multi well single pad operations from a-z.

 

[ceo_energemsier + 1,818]

The number of drilled but uncompleted wells in the United States continues to climb

 

https://www.eia.gov/todayinenergy/detail.php?id=39332

 

https://www.eia.gov/petroleum/drilling/#tabs-summary-1

[ceo_energemsier + 1,818]

Another set of technologies at the production optimization stage.

If shale is so bad, then what is the good oil? conventional? That will be the only option left. Although "stripper" wells provide a signification pil volume in the US, unless you run them through a lot of technologies to improve recovery and also to get a better understanding of the subsurface, they are just that marginal low volume high cost producer, that get shut in as soon as the prices start approaching 30$/bbl?

I have worked with a lot of "stripper" wells, from WV, IL, OH, CO, TX and have found that with the right geology (if they have the subsurface, high quality rocks) and applying new techs like the ones from the shale patch they can have a significant life extension and volume production enhancement. Tech goes to help all types of formations if they are the right kind, applied correctly and among a host of other factors at each step.

 

 

http://www.production-optimization-rockies.com/program/?utm_source=London Business Conferences&utm_medium=email&utm_campaign=10525898_BP19 - Production - 6%2F5%2F19&dm_i=SRO,69LU2,NHG4P3,OPUBG,1

[Falcon + 222]

Shale Technology Luddites will always be in denial.

Technology will prevail in US Shale.

All these experts of  oil industry sagacity will eventually have to concede to the shale oil miracle.

I know, I know Chevron and Occidental want Anadarko so they can loose money. Right ?

Warren Buffet wants a piece of the Permian.  He's never been a very smart investor. Yea.

Anadarko lost money because they were run by a Board of Directors made up of a bunch of Hedgefund types that knew nothing about the oil industry.  THEY DIDN'T HAVE THE KNOWLEDGE OR COMMON SENSE TO IMPLEMENT THE NEW TECHNOLOGY.

Using more sand is hardly "new technology".

The technology leaders new wells in Permian are breakeven in low $20's. EXXON targeting $15 breakeven  shale oil.

Oil Technology is not standing still.

Many producers overpaid for acreage. Many piled cash back into more overpriced acreage.  They will merge, be bought or go under.

Technology and new "manufacturing" drilling methodologies cost money. SIZE MATTERS.  

The "good 'ol days" of 80% , 100% or better rate of return (IRR) are gone.  It's a real business that will now require size and capital. 

Also, add the fact that offshore deep water from this point forward breakeven below $30 and there is a lot of money to be made in the segment for those that understand where it's going.

Granted the Service Companies are in a difficult position. Back during '12 or '13 when there were 1500+ rigs drilling for oil and gas the big three were making a killing.  But success draws competitors. Many of their field managers looked at the huge profits and said, "I can do that". It created many small startups buying 5 or 10 rigs and undercutting big boys prices. The large service company's then focused on the more analytical and seismic end of business.  It didn't and will never make up for the loss of drilling business.

 

Edited May 7, 2019 by Falcon

[ceo_energemsier + 1,818]

US Oil, Gas Industry Sets Production, Export Records

May 2, 2019 Alex Mills

Texas has a reputation of being a leader in energy production from coast-to-coast. That reputation has grown internationally as Texas leads the nation with dramatic increases in oil and natural gas production and exports.

The International Energy Agency (IEA) recently called the rise in production in Texas and the U.S. “the standout champion of global supply growth” and it expects the trend to continue.

“The second wave of the U.S. shale revolution is coming,” IEA Executive Director Faith Birol was quoted in the April issue of the American Oil and Gas Reporter. “It will see the United States account for 70 percent of the rise in global oil production and some 75 percent of the expansion in liquefied natural gas trade over the next five years. This will shake up international oil and gas trade flows, with profound implications for the geopolitics of energy.”

The U.S. Department of Energy’s Energy Information Administration (EIA) reports both oil and dry natural gas production set U.S. records in February. Oil production hit 12.1 billion barrels per day, Natural gas soared to 89.2 billion cubic feet per day, the highest for any month since EIA began tracking monthly dry natural gas production in 1973.

Crude oil, refined petroleum products, and natural gas exports from the U.S. continue to increase and imports continue to decline.

 

EIA reports U.S. net petroleum imports fell 1.5 million barrels per day in 2018 to an average of 2.3 million barrels per day, the lowest level in more than 50 years. EIA projects net oil and petroleum imports will continue to fall to an average of 1.0 million barrels per day in 2019 and will become a net exporter in 2020.

“And the same story line is playing out for natural gas and natural gas liquids (NGLs), too,” the American Oil and Gas Report stated. “Consequently, exports of everything from natural gas to gasoline, and from distillate fuel oil to propane and ethane, are at unprecedented levels.”

The volumes of petroleum increases have been created through technological developments in drilling, completion, and production techniques developed in Texas and throughout the U.S. that has been blessed with ultralow-permeability source rocks that has held massive amounts of hydrocarbons. The multiple pay zones in the Permian Basin of West Texas have been the leading target, which has produced a multiple mix of liquid and gas hydrocarbons.

“Greater U.S. exports to global markets strengthen oil security around the world,” Birol said. “Buyers of crude oil, particularly in Asia, where demand is growing fastest, have a wider choice of suppliers. This gives them more operational and trading flexibility, reducing their reliance on traditional long-term supply contracts.”

Alex Mills is the former President of the Texas Alliance of Energy Producers. The opinions expressed are solely of the author.

[ceo_energemsier + 1,818]

ExxonMobil Corp. has financed the Liza Phase 2 development offshore Guyana after receiving government and regulatory approvals. Liza Phase 2 will produce as much as 220,000 b/d, and ExxonMobil forecasts the Stabroek block will produce more than 750,000 b/d by 2025.

Six drill centers are planned to host about 30 wells, including 15 production, 9 water injection, and 6 gas injection wells. Phase 2 startup is expected in mid-2022.

Liza Phase 2 is expected to cost $6 billion, including a lease capitalization cost of $1.6 billion for the Liza Unity floating production, storage, and offloading vessel.

Liza Phase 1 remains on schedule to come on stream by first-quarter 2020. It will produce as much as 120,000 b/d of oil at peak, utilizing the Liza Destiny FPSO, which is expected to arrive offshore Guyana in the third quarter.

Pending government and regulatory approvals, a final investment decision is expected later this year for Phase 3 of development, Payara, which is expected to produce 180,000-220,000 b/d with startup as early as 2023.

ExxonMobil is evaluating additional development potential in other areas of the Stabroek block, including at the Turbot area and Hammerhead.

By Dec. 31, ExxonMobil expects to be operating four drillships offshore Guyana.

[Mike Shellman + 548]

4 hours ago, Falcon said:

Shale Technology Luddites will always be in denial.

Yes, well, its important to understand the difference in stuffing more sand into a longer lateral and meaningful "technological improvements;" so far the former has led to much higher productivity, but also higher well costs and no profitability improvements on a consistent quarter to quarter basis. The shale oil industry is still outspending revenue. 1Q19 it did not deleverage diddly. Drilling wells faster does not mean squat other than more problems down the road for production hands. Well "optimization" (gimme a break!) has led to over drilling, sky rocketing GOR increases and steeper decline rates. Want  to know why the DUC count keeps going up? Because half of those 8,500 wells are not economical to complete. Encana, the master of mass manufacturing and efficiency of scale in the Midland Basin lost +$250MM 1Q19. Concho, the biggest shale oil producer in the Permian lost money, same quarter; I am sure when it bought RSP last year for $79K an acre it thought its money losing days were over too. Oxy will end up paying over 60K per undeveloped net acre, all of its cash consideration to Anadarko...borrowed. Warren likes guaranteed dividends.  

Stripper wells don't have anything to do with any of this. Neither does Guyana. Exxon spent $2.5B, onshore N. America and made $93MM. Whoop. Hows that going to help pay back the $6.6B BOPCO buy? 

What's good oil? In America, under good 'ol free enterprise and capitalism, the only good oil is profitable oil. Debt and oil have never mixed, not ever. Its not now either.  

You guys don't need to correct me, or label me (I am IN the oil business with a checkbook, including once, before I got smart, the shale oil business)...you need to focus on convincing the people with the money they're wrong to be getting weak in the knees about loaning the shale oil industry mo' money. 1Q19 didn't make it any easier; yikes. That was awful. Not even technology saved them last quarter. 

 

 

[DanilKa + 443]

5 hours ago, Falcon said:

Shale Technology Luddites will always be in denial.

Funny statement from someone who doesn't know how to spell "proppant" or that it practically not used in shale wells (just check price of CarboCeramics stock if any doubts).

CoreLab is making most of its money in reservoir characterization and desperately trying to stay relevant. I'm not very familiar with perforating technology CEO speaks of but I haven't find anything which was not like 10 years old already (addressable switches, pre-assembled guns).

When wells are drilled 300-400' apart, there is little desire to spend money on logging or core testing, hence stock performance. CoreLab is not unique, all services got clobbered.

I'm not arguing idea of hydrocarbons production from shale - its a massive (but crap) resource. My issue is with near-ZIRP which resulted in miss-allocation of capital leading to speculative debt-fueled frenzy which won't end well for less sophisticated investors. Don't hold the bag for too long...

[DanilKa + 443]

5 hours ago, Falcon said:

Warren Buffet want a piece of the Permian.  He's never been a very smart investor. Yea.

^^this; admitting buying Amazon; under-performing S&P for years - great men is loosing it...

[Falcon + 222]

34 minutes ago, Mike Shellman said:

 

You guys don't need to correct me, or label me (I am IN the oil business with a checkbook . . . . .you need to focus on convincing the people with the money they're wrong to be getting weak in the knees about loaning the shale oil industry mo' money. 1Q19 didn't make it any easier; yikes. That was awful. Not even technology saved them last quarter. 

 

 

Sorry for your loss. A one needs more than a checkbook to make it in the shale business going forward.   As I stated most of the foolish money that thought oil would sell for $100+ forever were wrong and gone (or will be gone). 

WTI was selling @ $42 at Christmas.  Just exposed the vulnerability of the cowboys running around the basins drilling quicky "good enough wells".  Won't cut it anymore.

The latest advancements have just come into use on last year or so. 

Hess said new wells drilled 2018 55% return at $50 oil. In 2017 only 15%.

Occidental said they had 40 rigs working.  This year producing more oil with 16 rigs. 

Things change.  Technology continues to improve.  It's just not the small or mid independents that haven't implemented new practices and technology.  Look at Anadarko, a very large independent .

Some ask why haven't more independent been acquired.  My guess, the big boys believe the prices/margins will be squeezed again. Each rebound cucle delivers lower highs.  Anadarko was cheap due to poor performance.  Others could go lower before taken out.

Any open unbiased thinking man can see what's coming.

Timing, that's anyone's guess.

[Falcon + 222]

27 minutes ago, DanilKa said:

Funny statement from someone who doesn't know how to spell "proppant" 

Who is this my 1st grade teacher Mrs. Baxter ? 

When can't debate the issue pick on a misspelled word.

If you've ever taken an English Lit course you might have learned Shakespear (I mean Shakspeare) was a poor speller. Good company to keep. LOL

[DanilKa + 443]

16 minutes ago, Falcon said:

Who is this my 1st grade teacher Mrs. Baxter ? 

When can't debate the issue pick on a misspelled word.

If you've ever taken an English Lit course you might have learned Shakespear (I mean Shakspeare) was a poor speller. Good company to keep. LOL

I wouldn't be picking on misspelled word but couldn't resist because it illustrated your apparent lack of understanding of shale industry. Main driver behind production growth is none of the factors your stated but longer laterals and higher sand intensity. Normalized to lateral length and amount of placed sand - productivity is declining. Which is expected, considering interference between clusters and wells.

[Falcon + 222]

15 minutes ago, DanilKa said:

I wouldn't be picking on misspelled word but couldn't resist because it illustrated your apparent lack of understanding of shale industry. Main driver behind production growth is none of the factors your stated but longer laterals and higher sand intensity. 

Tell that to Occidental , Chevron, EXXON. Hess , etc

You don't get to $20 breakeven with more sand. Please. 

Your stuck in circa 2016 mentality.

Believe what you want. 

Luddites are in denial.

[Mike Shellman + 548]

1 hour ago, Falcon said:

A one needs more than a checkbook to make it in the shale business going forward.  

Well, actually, I made lots of money in the shale oil thing. That however means nothing as to its role in the long term hydrocarbon health of our country. The quote above suggests you benefit from the shale oil phenomena as an employee, or a royalty owner? Or a private equity coordinator looking for big pay days, or high yields? Shale oil extraction is a business and the business of shale oil extraction is not looky too good. If the business fails, all beneficiaries fail along with it, including the American public. 

[DanilKa + 443]

22 minutes ago, Falcon said:

Tell that to Occidental , Chevron, EXXON. Hess , etc

You don't get to $20 breakeven with more sand. Please. 

Your stuck in circa 2016 mentality.

Believe what you want. 

Luddites are in denial.

You get $20 breakeven by overstating EUR and creating accounting. Keep drinking Kool-Aid

[Falcon + 222]

1 hour ago, DanilKa said:

You get $20 breakeven by overstating EUR and creating accounting. Keep drinking Kool-Aid

The sandman speaks. 

Yea, fracers use more sand.  Who cares. For the 22nd time that's not technology, it's not what I and others are talking about.   If you to have an honest debate discuss the issues. Don't keep talking about sand and accusing oil companies of lying about their Permian breakeven. 

I'm sorry you lost money on Shale.  You are not alone.  Put it behind you and move on. 

"Keep drinking Kool-Aid" . Oh so clever. Did you just make that up yourself.

I'm done talking about sand.  Wait and see. Call me in a year. 

Edited May 7, 2019 by Falcon

[Douglas Buckland + 6,308]

 

19 hours ago, Falcon said:

Shale Technology Luddites will always be in denial.

Technology will prevail in US Shale.

All these experts of  oil industry sagacity will eventually have to concede to the shale oil miracle.

I know, I know Chevron and Occidental want Anadarko so they can loose money. Right ?

Warren Buffet wants a piece of the Permian.  He's never been a very smart investor. Yea.

Anadarko lost money because they were run by a Board of Directors made up of a bunch of Hedgefund types that knew nothing about the oil industry.  THEY DIDN'T HAVE THE KNOWLEDGE OR COMMON SENSE TO IMPLEMENT THE NEW TECHNOLOGY.

Using more sand is hardly "new technology".

The technology leaders new wells in Permian are breakeven in low $20's. EXXON targeting $15 breakeven  shale oil.

Oil Technology is not standing still.

Many producers overpaid for acreage. Many piled cash back into more overpriced acreage.  They will merge, be bought or go under.

Technology and new "manufacturing" drilling methodologies cost money. SIZE MATTERS.  

The "good 'ol days" of 80% , 100% or better rate of return (IRR) are gone.  It's a real business that will now require size and capital. 

Also, add the fact that offshore deep water from this point forward breakeven below $30 and there is a lot of money to be made in the segment for those that understand where it's going.

Granted the Service Companies are in a difficult position. Back during '12 or '13 when there were 1500+ rigs drilling for oil and gas the big three were making a killing.  But success draws competitors. Many of their field managers looked at the huge profits and said, "I can do that". It created many small startups buying 5 or 10 rigs and undercutting big boys prices. The large service company's then focused on the more analytical and seismic end of business.  It didn't and will never make up for the loss of drilling business.

 

'Shale technology will prevail'....what is "shale technology"?

Massive Hydraulic Fracturing was being performed regularly in Texas (Austin Chalk, Cotton Valley, etc...) back in the early 1980's. This technology cannot be attributed to the 'shale oil miracle'. It may have been tailored to meet shale requirements, but the technology was developed eons ago and improved on since then in conventional plays.

Rig technology has been steadily improving worldwide. I do not consider a fat driller in a cyber chair as a quantum leap in technology. Iron roughnecks, pipe spinners, top drives, etc.... were developed elsewhere.

Rational operators would have drilled the 'sweet spots' first. I seriously doubt we'll see an appreciable increase in rock quality in the future.

I was utilizing a 3D viewing room in Poza Rica, Mexico to plan wells almost 20 years ago. I don't think this technology can be attributed to the shale fiasco.

Can anyone list drilling technologies which have been developed unique to shale drilling?

[ceo_energemsier + 1,818]

Shale EOR Delivers, So Why Won’t the Sector Go Big?

 

Trent Jacobs, JPT Digital Editor | 01 May 2019

 

The oil is there. The gas is nearby. The process is proven.

But is there an appetite to put it all together and redefine what it means to be a shale producer? This is the key question looming over the future of enhanced oil recovery for tight shale reservoirs, or simply shale EOR.

To answer it, unconventional oil producers are trying to weigh the options from what amounts to a complicated pros-and-cons list.

Developing a shale EOR program may mean drawing resources away from new exploration projects that have quicker returns, the same conundrum that has stymied the US refracturing market. On the other hand, shale EOR boasts impressive economics for companies willing to reinvest in land and wells already paid for.

This financial tug-of-war has been playing out in the shale sector since the spring of 2016. That was when Houston-based EOG Resources let it be known that its shale EOR program was boosting production from vintage horizontal wells in its Eagle Ford Shale asset in south Texas.

News of the development quickly made the operator synonymous with shale EOR. It is now widely understood that all of these projects rely on the huff-and-puff injection process using natural gas as the special agent that can unlock those additional barrels. Other key details are coming to light as well—such as the expanding scope of success.

In a recent quarterly earnings statement, EOG said it continues to see “strong results” from around 150 EOR wells, more than a third of which were converted in 2018. Analysts and engineering consultants have found about 100 other wells in the Eagle Ford that several other operators have converted into huff-and-puff injectors.

“It’s kind of incredible to see the data,” said John Watson, the senior research analyst who put together a report late last year that highlighted production details of shale EOR projects. After physically combing through filings at the Texas Railroad Commission (since they are not available to download), he found dozens of pad wells that saw a combined 10-fold rise in production above their trough.

Among the standouts, a group of 11 wells that reached a combined peak production rate in December 2011 of about 90,000 bbl a month. By August 2017, these wells were pumping out only 5,000 bbl. After gas injections began, the group produced 40,000 bbl a month—an average increase from about 15 B/D to 117 B/D per well.

Another case involved 14 wells that peaked at 330,000 bbl a month in 2013, then dropped to 10,000 bbl. Post injection, output increased to 170,000 bbl a month.

Watson’s report covers more than two dozen other shale EOR projects, though most lacked production results, revealing only project cost estimates. As opaque as the shale EOR effort has been thus far—at least outside of academic research—operators have shared these eye-openers for one simple reason: they have to. That is, if they want to receive the tax credits eligible for all EOR projects.

“I think there’s still a lot of mystery around what exactly is going on, and I think some of the operators want it to be that way,” said Watson, who as an analyst of the gas compressor market was drawn to investigate the new demand driver for the multimillion-dollar machines that are essential to the process.

Observers and proponents in the engineering consulting sector are emphasizing that the results above are not a fluke. The hard part here is that replicating them requires several factors to come together:

• Fracture networks and fluid properties must be optimal for injections
• Management must be willing to pioneer in uncertain territory and new technology
• The operator has both the time and money to develop the project
• Investors and lenders do not veto the upfront capital investment

 

Technical Success Is Not Enough

No matter how inspiring or representative the early results appear to be, they have not proven to be enough to warrant major investments by most of the shale sector. Experts believe there are thousands of potential shale EOR locations in the Eagle Ford alone, yet only a relative handful have undergone the process.

Further, less than a dozen shale producers are known to be testing injection operations of various scales in south Texas. A smaller number are understood be moving forward commercially, while another small group are trying to export the technique to horizontal wells in the Permian Basin of west Texas and in North Dakota’s Bakken Shale. Some will rely on CO₂, such as Occidental Petroleum’s Permian plans call for, but it appears the most popular approach will rely on natural gas.

Nick Volkmer, vice president of energy research for RS Energy in Calgary, gave one explanation for the cautious approach most operators are taking: “From a technical standpoint, [shale EOR] doesn’t seem as complex to us as discovering how to frac a well. (But) one of the big pieces with this process is that you want to have enough long-term data to be comfortable in that you’re actually increasing overall recovery as opposed to just accelerating production.”

Such certainty will be critical in lowering the perceived risk profile of shale EOR operations in light of the sector’s financial constraints. With access to new capital tightening, the struggle to realize the long-term value of shale EOR appears set to drag on. “It’s a drilling and completions play,” said George Grinestaff, who added that, “These gas injection projects are daunting to [the operators].”

Grinestaff is the founder and chief executive officer of Shale IOR in Houston, one of a handful of engineering consultancies that specialize in the EOR process. The company has used drones and fixed-wing aircraft to fly over the injection sites to confirm the types of equipment being used.

These findings, and other key details, of every known shale EOR project are in a 150-page report that the company is shopping to interested operators. “None of them have failed,” Grinestaff said, of the projects. “They’re all responding in a similar way.”

But barring a significant rise in crude prices, his conclusion is that the sector’s priority will continue to be firmly set on drilling new wells that deliver full returns in their first year. And even though the full benefit of shale EOR can be realized after the first injection cycle—unique compared with conventional EOR—the payout may take up to 2 years because of the cost to “fill up” the depleted wells with gas.

To adopt the long-term vision of shale EOR, producers will be required to redistribute time and resources to the effort. This has given rise to the cottage industry of shale EOR consultancies that believe they can accelerate the project cycle by taking on many of the homework assignments. Though they are bullish on the process, they know shale EOR cannot be done at scale through a cookie-cutter approach.  

“You can call me biased, but I don’t think it’s experimental anymore—at least in the Eagle Ford,” said Kaveh Ahmadi, the founder of Pometis Technology, a Houston-based startup focused on modeling shale EOR scenarios to help operators screen candidates. Ahamdi cautioned though that the process “is not a magic bullet” and that, by all accounts, the location of the project is essential to making it work.

One other key aspect he has studied is how long to inject and then soak the reservoir with gas. Ahmadi’s findings suggest that achieving high-enough pressures to maximize, or spread out, the contact area is essential to the process. This also creates a reason to believe that any new barrels of oil that make it to the surface are likely sourced from only a few inches into the rock, at most. “We say the production comes from the near-fracture areas, and that’s it,” said Ahmadi. “If you’re talking about the reservoir as if it contributes, it never does that.”

Another expert, Jeff Rutledge, left Marathon Oil last year after setting up that company’s first shale EOR pilot to start his own firm, QPlus Energy. He too is in the business of designing pilots for other operators and is impressed to see that the earliest EOR projects in the Eagle Ford appear to not have reached their economic limit.

“To me, you just draw the curves and it doesn’t look like it is slowing down, and some of those curves are 3 years old,” he said, referencing the fact that the number of huff-and-puff cycles that each well can go through is limited by the law of diminishing returns. For the shale sector, this is encouraging news since it expands the definition of commercial success.

But achieving success means understanding the reservoir and if its conditions are agreeable to the process. Some of the top factors include API gravity, gas-to-oil ratios, fault locations, external stresses, natural fractures, negative communication due to frac hits, etc. Where all these points align tend to be in the lighter hydrocarbon windows.

Rutledge said this sliver of potentially optimal conditions appears to follow the same geographic trends of the Eagle Ford—which means tens of thousands of horizontal wells could be EOR candidates. “The beauty of it is that, unlike going into a new area, say like in the Permian where you have to pay a lot of money for leases, these are all in existing leases,” he said. “You’re just going back into old wellbores.”

Circled in red are the areas that analysts are researching and believe that cyclic gas injections, or huff-and-puff, will perform best and extract the most crude. Source: GeoMark Research.

What Are the Bottlenecks?

The biggest holdup for shale EOR so far has involved access to the high-horsepower compressors that seem to work best. Chet Ozgen, a technical director with Nitech, a consultancy that has worked on various shale EOR projects over the past 3 years, said the interest in shale EOR has far outpaced the supply of these compressors.

“About 2 years ago, if you wanted to order a gas compressor to inject, you simply could not find one,” he said, adding that the waiting time both then and now is about 12–15 months. Ozgen pointed out that typical field compressors, the kind used to move gas through a sales line, have an upper limit of about 4,000 psi. “Here, we are talking about going up to 7,000 or 9,000 psi, and you don’t just pick those compressors up off the street,” he said.

A leading cause for the scarcity is the $4–4.5 million price tag of the most sought-after compressors, which are often referred to by the model number of their Caterpillar-made engines—the 3606. These high-horsepower engines must be paired with a piece of equipment called a frame that does the actual gas compression, and there are only two firms in the US that supply the full assembly.

The long wait is seen as worth it though, since the 3606 compressors are essential to minimizing the time it takes to see the effects of EOR. Ahmadi said early field results he has access to strongly indicate that “if you want to be successful, go big,” both in terms of the horsepower and the number of wells being converted to huff-and-puff injectors.  

The pilots that involve two to four wells on a pad may be good for learning the ropes, however, Ahmadi sees the best returns on what he calls “marquee projects” that involve at least 10 wells. Such large projects might even require two of the large compressor units on the same site. There are multiple factors that dictate performance, but the Simmons & Co. report that shows estimated project economics supports the idea that operators using the most capital are expecting big returns.

For instance, a 14-well injection project in Gonzales County that cost about $16 million is predicted to extract an additional 3.2 million bbl of oil from the lease. In the same county, a three-well EOR project with a bill of $7 million is estimated to add 600,000 bbl of incremental supply.

Grinestaff agrees and said low-cost pilots may fail to achieve economies of scale, and therefore could sour a company’s thoughts on spending much more. “They don’t want to start with $50 million projects,” he said. Getting past the pilot phase though would require such a large sum, so the argument is why not commit to it as early as possible?

Outside of sourcing the compressors, the next hurdle to clear is feeding them enough gas to meet their voracious appetites of about 15 million ft³/D each.  

Many locations might have enough supply for a single compressor, but the constraints start to kick in when trying to meet the input needs of more than two. This is an area where EOG is seen as having another major advantage: the company retained its midstream infrastructure while its neighboring peers sold theirs off in recent years to lower operating costs.

What They Are Trying to Figure Out

Once the compressor is on its way to the field, the complexities of shale EOR are only partially solved. “There are such interesting criteria for where this gas injection will work,” said Ozgen, who has high on his list the issue of confinement that is needed to keep the gas near enough to the well’s stimulated zone to drive oil flow.

Confinement. Vertically, confinement in the Eagle Ford, and elsewhere, has so far not been a big concern to practitioners. “Horizontally, we have a bigger problem,” said Ozgen, who explained that the worry here is over the long, tensile fractures that operators created via their early-generation stimulations.

While a large surface area for the gas to interact with is critical to achieving success, there are cases where the tensile fracture networks could be overly extensive, allowing the gas to spread quickly into adjacent wellbores. Ozgen has found that newer generations of hydraulic fracturing designs, ones aimed at generating near-wellbore complexity, are making for the best EOR candidates.

Other Reservoir Characteristics. Operators are turning to the consultants for pressure, volume, and temperature (PVT) analysis to understand how the injections will perform downhole. Rutledge uses PVT reports to find bubble-point data that then allows him to calculate the first-contact miscibility (FCM) pressure of the formation. Knowing the FCM means knowing the pressures at which the rich gas will begin affecting oil flow. Operators are being advised that the bottomhole injection pressure (which is related to the FCM) should not exceed the rock’s fracture gradient, otherwise, new geomechanical complications arise from refracturing the formation.

Soak Times. How long to leave the injected gas inside the formation, known as the soak time, represents yet another big question that companies are trying to nail down during their huff-and-puff pilots. Ahmadi noted that the answer might be simpler than most would expect. “We’re getting to the point where soak time doesn’t matter as much,” he said, justifying the position based on the different cycle times he has seen operators test: 30 days, 20 days, and 15 days.

The results tell Ahmadi that 30 days is too long because diffusion is not the dominant force at play in these wells, and is too slow to economically count on. “Inject as much as you can in the shortest amount of time,” he advised, adding that his studies show that shale EOR is driven by the area of gas contacting the rocks and the pressure—not diffusion.

The shortest cycle time Ahmadi has seen is 20 days and, theoretically, he said a successful outcome could be reached in even less time. “Optimizing the gas injection process means that soak times can be minimized, therefore increasing compressor utilization,” he explained.

Sequencing and communication. The order in which gas injections take place between a group of wells is the key to optimizing the approach. And a big deciding factor here is how the pad wells communicate, which the shale sector has learned is almost always the case.

Ozgen and others are using reservoir models to derisk the sequencing options. Based on his experience, Ozgen estimates that 50% of the scenarios where wells are highly communicative, which could be indicated by a history of intense frac hits during the completions phase, may turn out to be noneconomic. He compared this to converting isolated, individual wells to EOR, in which case the sequencing will have almost no impact on the economics.

In the worst cases, the big risk might be that the wells end up recycling the injected gas from one to the next without improving production. To sum up how critical sequencing is, Ozgen concluded: “If you do not find the correct order, you can lose money and your [incremental] recovery is horrible.”

 

[ceo_energemsier + 1,818]

Topic on shale tech , efficiencies

1) They can acquire larger acreage and drill and complete longer laterals for lower per foot

2) The data they acquire or will acquire for larger acreages will come in @ a lower cost and processing the large data base for sub surface geology, including 2D and 3D seismic (and or reprocessing existing 2D or 3D) , mapping of structures in the subsurface, analyzing the data and obtaining the interpretive results of that will be easier, and lower in costs using high tech computers and AI and IOT. Same goes with geochemistry and geophysics.

3) The majors also have access to easier and lower costs financing. They can issue more shares for one and people continue to buy them, they also have access to global financial institutions willing to finance at favorable terms.

4) From the post, you make it sound like all the execs and management are idiots at these companies, but not all of them are.

5) Lack of takeaway capacity in the Permian will be resolved within 2 yrs, maybe 3 at the max for the projected oil gas and liquids increased production.

6) Not all shale wells have drastic decline curves. Once again it comes back to using the right tech or suite of techs to acquire the quality rocks to drill. If you buy "schitty" quality of anything you get "schitty" results. Companies have gone bankrupt and have had to offload their shale acreages because they purchase not so good assets and overpaid for them. Recall the days when companies were paying 20,000-100,000$ an acre (Shell paid 100,000$/acre in the Eagle Ford and ended up selling it for very very cheap, the rancher that was paid the bonuses was the real winner). A new shale industry practice should emerge and be used in acreage leasing/acquisitions i.e. landowners are paid a "reasonable" fee or option fee to evaluate the area/acreage of interest. I can elaborate on this later if there is interest.

7) Tech is the key for success at each and every aspect of shale development as it is in any other advanced business, or medicine or any enterprise that is high value , high risk. Using combinations of techs that are synergistic and complementary reduces costs at all levels and brings unprecedented efficiencies. Example using combination of 2D/3D and other seismic techs to develop an accurate picture of the subsurface and identifying the shale structures in terms of their geological value in terms of holding hydrocarbons. Followed up by finding and identifying where there are the naturally occurring clusters of natural perforations or fractures in the shale where the hydrocarbons will accumulate and post drilling and completion will have an area where due to natural pressure and inflow will maintain good production WITHOUT DRASTIC decline. We have had tremendous success and have experienced extremely low decline rates comparatively. Majority of companies dont  follow this or use this geo tool. It is akin to have a phlebotomist trying to draw blood from a not so good spot. Medicine has had a huge impact on oil and gas in terms of application of technologies, CAT scan, MRI etc among others. Drilling and completion techs used in combination to provide the best suited application in that specific formation or acreage, and remember shale isnt homogeneous. Geosteering techs , completion techs, water use, type of proppants and the list goes on.

8.) Initial recovery in most cases is very low, so shale EOR enhances that in a large perspective.

 

9) I think you maybe living in the past about the majors today, they are becoming nimble and able to adapt. BP, XOM others are paying lot more attention to new energized talent that are extremely tech savvy and working towards disruptive techs and processes that are bringing about major changes. They are promoting out of the box thinking by being proactively seeking and employing talent that does that. Due to the low oil price environment for longer, several majors have had good success in cutting their overheads.

10) The majors have cash available and easy access to financing to fund new tech R&D or acquire it from others or buy entire companies and or are able to form JVs and enterprises with service companies to do develop or add onto existing techs. BP, XOM others are continuously funding start up techs.

11) Another cost reduction, production improvement process is the multi well pad drilling, smaller companies using service providers under contract can also achieve it but larger companies may also have their own specialized fleets for this or due to their large acreages maybe able to get better rates for retaining service contractors for this purpose plus other services. Even for small companies , multi-well  pad drilling proves very productive and cost effective and greatly improves the bottom line, given all other aspects are also done in a  very hitech streamlined manner. I have seen production levels ranging from 9,000bopd-28,000bopd (excluding gas, condensates, ngls etc) from a single pad. I have used this process in conventional fields, mature fields and have seen amazing production results.

I have a business segment that re-evaluates marginal fields, bypassed overlooked fields, stripper wells and orphaned wells and apply various techs after the target prospect qualifies for some criteria and the results have been amazing. The oil and gas industry with all its various types of resources, conventional , unconventional, are technology driven at every stage.

COming back to Shale EOR:

 

 

Shale EOR Delivers, So Why Won’t the Sector Go Big?

 

Trent Jacobs, JPT Digital Editor | 01 May 2019

 

The oil is there. The gas is nearby. The process is proven.

But is there an appetite to put it all together and redefine what it means to be a shale producer? This is the key question looming over the future of enhanced oil recovery for tight shale reservoirs, or simply shale EOR.

To answer it, unconventional oil producers are trying to weigh the options from what amounts to a complicated pros-and-cons list.

Developing a shale EOR program may mean drawing resources away from new exploration projects that have quicker returns, the same conundrum that has stymied the US refracturing market. On the other hand, shale EOR boasts impressive economics for companies willing to reinvest in land and wells already paid for.

This financial tug-of-war has been playing out in the shale sector since the spring of 2016. That was when Houston-based EOG Resources let it be known that its shale EOR program was boosting production from vintage horizontal wells in its Eagle Ford Shale asset in south Texas.

News of the development quickly made the operator synonymous with shale EOR. It is now widely understood that all of these projects rely on the huff-and-puff injection process using natural gas as the special agent that can unlock those additional barrels. Other key details are coming to light as well—such as the expanding scope of success.

In a recent quarterly earnings statement, EOG said it continues to see “strong results” from around 150 EOR wells, more than a third of which were converted in 2018. Analysts and engineering consultants have found about 100 other wells in the Eagle Ford that several other operators have converted into huff-and-puff injectors.

“It’s kind of incredible to see the data,” said John Watson, the senior research analyst who put together a report late last year that highlighted production details of shale EOR projects. After physically combing through filings at the Texas Railroad Commission (since they are not available to download), he found dozens of pad wells that saw a combined 10-fold rise in production above their trough.

Among the standouts, a group of 11 wells that reached a combined peak production rate in December 2011 of about 90,000 bbl a month. By August 2017, these wells were pumping out only 5,000 bbl. After gas injections began, the group produced 40,000 bbl a month—an average increase from about 15 B/D to 117 B/D per well.

Another case involved 14 wells that peaked at 330,000 bbl a month in 2013, then dropped to 10,000 bbl. Post injection, output increased to 170,000 bbl a month.

Watson’s report covers more than two dozen other shale EOR projects, though most lacked production results, revealing only project cost estimates. As opaque as the shale EOR effort has been thus far—at least outside of academic research—operators have shared these eye-openers for one simple reason: they have to. That is, if they want to receive the tax credits eligible for all EOR projects.

“I think there’s still a lot of mystery around what exactly is going on, and I think some of the operators want it to be that way,” said Watson, who as an analyst of the gas compressor market was drawn to investigate the new demand driver for the multimillion-dollar machines that are essential to the process.

Observers and proponents in the engineering consulting sector are emphasizing that the results above are not a fluke. The hard part here is that replicating them requires several factors to come together:

• Fracture networks and fluid properties must be optimal for injections
• Management must be willing to pioneer in uncertain territory and new technology
• The operator has both the time and money to develop the project
• Investors and lenders do not veto the upfront capital investment

 

Technical Success Is Not Enough

No matter how inspiring or representative the early results appear to be, they have not proven to be enough to warrant major investments by most of the shale sector. Experts believe there are thousands of potential shale EOR locations in the Eagle Ford alone, yet only a relative handful have undergone the process.

Further, less than a dozen shale producers are known to be testing injection operations of various scales in south Texas. A smaller number are understood be moving forward commercially, while another small group are trying to export the technique to horizontal wells in the Permian Basin of west Texas and in North Dakota’s Bakken Shale. Some will rely on CO₂, such as Occidental Petroleum’s Permian plans call for, but it appears the most popular approach will rely on natural gas.

Nick Volkmer, vice president of energy research for RS Energy in Calgary, gave one explanation for the cautious approach most operators are taking: “From a technical standpoint, [shale EOR] doesn’t seem as complex to us as discovering how to frac a well. (But) one of the big pieces with this process is that you want to have enough long-term data to be comfortable in that you’re actually increasing overall recovery as opposed to just accelerating production.”

Such certainty will be critical in lowering the perceived risk profile of shale EOR operations in light of the sector’s financial constraints. With access to new capital tightening, the struggle to realize the long-term value of shale EOR appears set to drag on. “It’s a drilling and completions play,” said George Grinestaff, who added that, “These gas injection projects are daunting to [the operators].”

Grinestaff is the founder and chief executive officer of Shale IOR in Houston, one of a handful of engineering consultancies that specialize in the EOR process. The company has used drones and fixed-wing aircraft to fly over the injection sites to confirm the types of equipment being used.

These findings, and other key details, of every known shale EOR project are in a 150-page report that the company is shopping to interested operators. “None of them have failed,” Grinestaff said, of the projects. “They’re all responding in a similar way.”

But barring a significant rise in crude prices, his conclusion is that the sector’s priority will continue to be firmly set on drilling new wells that deliver full returns in their first year. And even though the full benefit of shale EOR can be realized after the first injection cycle—unique compared with conventional EOR—the payout may take up to 2 years because of the cost to “fill up” the depleted wells with gas.

To adopt the long-term vision of shale EOR, producers will be required to redistribute time and resources to the effort. This has given rise to the cottage industry of shale EOR consultancies that believe they can accelerate the project cycle by taking on many of the homework assignments. Though they are bullish on the process, they know shale EOR cannot be done at scale through a cookie-cutter approach.  

“You can call me biased, but I don’t think it’s experimental anymore—at least in the Eagle Ford,” said Kaveh Ahmadi, the founder of Pometis Technology, a Houston-based startup focused on modeling shale EOR scenarios to help operators screen candidates. Ahamdi cautioned though that the process “is not a magic bullet” and that, by all accounts, the location of the project is essential to making it work.

One other key aspect he has studied is how long to inject and then soak the reservoir with gas. Ahmadi’s findings suggest that achieving high-enough pressures to maximize, or spread out, the contact area is essential to the process. This also creates a reason to believe that any new barrels of oil that make it to the surface are likely sourced from only a few inches into the rock, at most. “We say the production comes from the near-fracture areas, and that’s it,” said Ahmadi. “If you’re talking about the reservoir as if it contributes, it never does that.”

Another expert, Jeff Rutledge, left Marathon Oil last year after setting up that company’s first shale EOR pilot to start his own firm, QPlus Energy. He too is in the business of designing pilots for other operators and is impressed to see that the earliest EOR projects in the Eagle Ford appear to not have reached their economic limit.

“To me, you just draw the curves and it doesn’t look like it is slowing down, and some of those curves are 3 years old,” he said, referencing the fact that the number of huff-and-puff cycles that each well can go through is limited by the law of diminishing returns. For the shale sector, this is encouraging news since it expands the definition of commercial success.

But achieving success means understanding the reservoir and if its conditions are agreeable to the process. Some of the top factors include API gravity, gas-to-oil ratios, fault locations, external stresses, natural fractures, negative communication due to frac hits, etc. Where all these points align tend to be in the lighter hydrocarbon windows.

Rutledge said this sliver of potentially optimal conditions appears to follow the same geographic trends of the Eagle Ford—which means tens of thousands of horizontal wells could be EOR candidates. “The beauty of it is that, unlike going into a new area, say like in the Permian where you have to pay a lot of money for leases, these are all in existing leases,” he said. “You’re just going back into old wellbores.”

Circled in red are the areas that analysts are researching and believe that cyclic gas injections, or huff-and-puff, will perform best and extract the most crude. Source: GeoMark Research.

What Are the Bottlenecks?

The biggest holdup for shale EOR so far has involved access to the high-horsepower compressors that seem to work best. Chet Ozgen, a technical director with Nitech, a consultancy that has worked on various shale EOR projects over the past 3 years, said the interest in shale EOR has far outpaced the supply of these compressors.

“About 2 years ago, if you wanted to order a gas compressor to inject, you simply could not find one,” he said, adding that the waiting time both then and now is about 12–15 months. Ozgen pointed out that typical field compressors, the kind used to move gas through a sales line, have an upper limit of about 4,000 psi. “Here, we are talking about going up to 7,000 or 9,000 psi, and you don’t just pick those compressors up off the street,” he said.

A leading cause for the scarcity is the $4–4.5 million price tag of the most sought-after compressors, which are often referred to by the model number of their Caterpillar-made engines—the 3606. These high-horsepower engines must be paired with a piece of equipment called a frame that does the actual gas compression, and there are only two firms in the US that supply the full assembly.

The long wait is seen as worth it though, since the 3606 compressors are essential to minimizing the time it takes to see the effects of EOR. Ahmadi said early field results he has access to strongly indicate that “if you want to be successful, go big,” both in terms of the horsepower and the number of wells being converted to huff-and-puff injectors.  

The pilots that involve two to four wells on a pad may be good for learning the ropes, however, Ahmadi sees the best returns on what he calls “marquee projects” that involve at least 10 wells. Such large projects might even require two of the large compressor units on the same site. There are multiple factors that dictate performance, but the Simmons & Co. report that shows estimated project economics supports the idea that operators using the most capital are expecting big returns.

For instance, a 14-well injection project in Gonzales County that cost about $16 million is predicted to extract an additional 3.2 million bbl of oil from the lease. In the same county, a three-well EOR project with a bill of $7 million is estimated to add 600,000 bbl of incremental supply.

Grinestaff agrees and said low-cost pilots may fail to achieve economies of scale, and therefore could sour a company’s thoughts on spending much more. “They don’t want to start with $50 million projects,” he said. Getting past the pilot phase though would require such a large sum, so the argument is why not commit to it as early as possible?

Outside of sourcing the compressors, the next hurdle to clear is feeding them enough gas to meet their voracious appetites of about 15 million ft³/D each.  

Many locations might have enough supply for a single compressor, but the constraints start to kick in when trying to meet the input needs of more than two. This is an area where EOG is seen as having another major advantage: the company retained its midstream infrastructure while its neighboring peers sold theirs off in recent years to lower operating costs.

What They Are Trying to Figure Out

Once the compressor is on its way to the field, the complexities of shale EOR are only partially solved. “There are such interesting criteria for where this gas injection will work,” said Ozgen, who has high on his list the issue of confinement that is needed to keep the gas near enough to the well’s stimulated zone to drive oil flow.

Confinement. Vertically, confinement in the Eagle Ford, and elsewhere, has so far not been a big concern to practitioners. “Horizontally, we have a bigger problem,” said Ozgen, who explained that the worry here is over the long, tensile fractures that operators created via their early-generation stimulations.

While a large surface area for the gas to interact with is critical to achieving success, there are cases where the tensile fracture networks could be overly extensive, allowing the gas to spread quickly into adjacent wellbores. Ozgen has found that newer generations of hydraulic fracturing designs, ones aimed at generating near-wellbore complexity, are making for the best EOR candidates.

Other Reservoir Characteristics. Operators are turning to the consultants for pressure, volume, and temperature (PVT) analysis to understand how the injections will perform downhole. Rutledge uses PVT reports to find bubble-point data that then allows him to calculate the first-contact miscibility (FCM) pressure of the formation. Knowing the FCM means knowing the pressures at which the rich gas will begin affecting oil flow. Operators are being advised that the bottomhole injection pressure (which is related to the FCM) should not exceed the rock’s fracture gradient, otherwise, new geomechanical complications arise from refracturing the formation.

Soak Times. How long to leave the injected gas inside the formation, known as the soak time, represents yet another big question that companies are trying to nail down during their huff-and-puff pilots. Ahmadi noted that the answer might be simpler than most would expect. “We’re getting to the point where soak time doesn’t matter as much,” he said, justifying the position based on the different cycle times he has seen operators test: 30 days, 20 days, and 15 days.

The results tell Ahmadi that 30 days is too long because diffusion is not the dominant force at play in these wells, and is too slow to economically count on. “Inject as much as you can in the shortest amount of time,” he advised, adding that his studies show that shale EOR is driven by the area of gas contacting the rocks and the pressure—not diffusion.

The shortest cycle time Ahmadi has seen is 20 days and, theoretically, he said a successful outcome could be reached in even less time. “Optimizing the gas injection process means that soak times can be minimized, therefore increasing compressor utilization,” he explained.

Sequencing and communication. The order in which gas injections take place between a group of wells is the key to optimizing the approach. And a big deciding factor here is how the pad wells communicate, which the shale sector has learned is almost always the case.

Ozgen and others are using reservoir models to derisk the sequencing options. Based on his experience, Ozgen estimates that 50% of the scenarios where wells are highly communicative, which could be indicated by a history of intense frac hits during the completions phase, may turn out to be noneconomic. He compared this to converting isolated, individual wells to EOR, in which case the sequencing will have almost no impact on the economics.

In the worst cases, the big risk might be that the wells end up recycling the injected gas from one to the next without improving production. To sum up how critical sequencing is, Ozgen concluded: “If you do not find the correct order, you can lose money and your [incremental] recovery is horrible.”

 

 

____________________________

AI and shale

 

Artificial intelligence firm gets second funding round for shale

 

Artificial Intelligence (AI) is gaining favor across the oil patch. OAG Analytics, an AI-specialist focused on oil and gas, announced this week it has received a second round of strategic funding from Rice Investment Group. Rice is a $200 million strategy fund based in Pennsylvania that targets oil and gas.

OAG said funding will be used to help customers add AI to the their asset portfolios. Subsurface engineers and scientists use AI to organize data and run billions of simulations before deploying capital, OAG said. OAG’s system provides a cloud-based platform that has interactive visualizations. The technology has already been used in the Permian, Eagle Ford, Bakken, Anadarko and Haynesville shale plays. According to the company, U.S. operators have optimized more than $10 billion in capital expenditures using OAG’s tech. "Our industry is entering the next phase of the shale revolution by moving to full-field development. As such, we need the next 

generation of analytical capabilities to maximize capital efficiency," said Derek Rice, partner at Rice Investment Group and Director at OAG. "Large-scale development optimization requires an in-depth understanding of hundreds of uncorrelated data points, which OAG provides through data management and advanced analytics to support profitable decision making. We are thrilled to partner with OAG's team, and believe our insights and experience as an operator will continue to add value to the platform," Rice said.

OAG was founded by Luther Birdzell, an entrepreneur, data scientist and engineer focused on energy efficiency, AI and self-service machine learning.