Why is bigger better in the Permian?

I have a question for you...

Why do the major players who are moving into the Permian, and other shale plays, think they can make it work any better than the small or mid cap outfits?

It does not matter who owns or drills these wells, the drastic decline curves, lack of pipeline capacity, lack of experienced personnel and the available technology remains the same.

From my perspective, they have deeper pockets, which will simply allow them to bleed longer.

Furthermore, with their top heavy organizations, bloated HR and HSE departments and their process driven organizations (if it is not in the manual you will not do it, no innovation or thinking out of the box allowed), their overhead is much greater than the smaller operators and their cost/bbl higher.

The big outfits do NOT have any magical new technology available to them. The technology is generally advanced by the service companies and is available to anyone willing to pay for it.

So again, why do the big players think they will do better in the shale oil arena?

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Good question. Some may have an economy of scale which allows them to do things small players cannot afford (such as Permian-wide water feeding pipeline to avoid trucking etc). Fewer players may better coordinate (collude...) activities to reduce competition for scarce beds, HHP, rigs etc. 

I don’t think main driver is elusive cost savings - majors need access to reserves, else they tossed on RRR. 

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I think part of the answer is also cost of finance. 

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(edited)

16 hours ago, Douglas Buckland said:

I have a question for you...

Why do the major players who are moving into the Permian, and other shale plays, think they can make it work any better than the small or mid cap outfits?

It does not matter who owns or drills these wells, the drastic decline curves, lack of pipeline capacity, lack of experienced personnel and the available technology remains the same.

From my perspective, they have deeper pockets, which will simply allow them to bleed longer.

Furthermore, with their top heavy organizations, bloated HR and HSE departments and their process driven organizations (if it is not in the manual you will not do it, no innovation or thinking out of the box allowed), their overhead is much greater than the smaller operators and their cost/bbl higher.

The big outfits do NOT have any magical new technology available to them. The technology is generally advanced by the service companies and is available to anyone willing to pay for it.

So again, why do the big players think they will do better in the shale oil arena?

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.  

mail?url=https%3A%2F%2Fwww.spe.org%2Fmed

“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.”

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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.

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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.

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Multi-well pad drilling—when multiple wells are drilled from a single drill site—is allowing companies to produce oil more efficiently and at a significant cost savings, resulting in record production for shale oil producers.

The market for multi-well pad drilling technology is expected to surpass US$180 billion by 2024, according to a report by Global Market Insights, as oil & gas sector companies look to more unconventional extraction methods to meet rising demand for energy resources. Analysts expect to see the most growth in the North American onshore market segment due to the large number of shale exploration and production projects.

“U.S. producers are enjoying a second wave of growth so extraordinary that in 2018 their increase in liquids production could equal global demand growth,” the International Energy Agency (IEA) said in a February report. “We are seeing United States production rising very, very dramatically before our very eyes and that’s likely to continue in 2018,” Neil Atkinson, head of the IEA oil industry and markets division, told CNBC. The IEA believes the United States may well surpass Saudi Arabia and Russia as the world’s leading energy producer by 2019.

Not to be outdone, Canada’s oil producers are also working hard to grab a bigger piece of the global oil market, with a focus on the Duvernay and Montney formations, which “could rival the most prolific U.S. shale fields,” reports the Financial Post. “Canada, by contrast, offers many of the same advantages that allowed oil firms to launch the shale revolution in the United States: numerous private energy firms with appetite for risk; deep capital markets; infrastructure to transport oil; low population in regions that contain shale reserves; and plentiful water to pump into shale wells.”

Multi-well pad technology behind shale oil boom

Traditional extraction methods involve drilling down vertically from a new pad—the location that houses the wellhead—for each new well, which means that even if the new location is merely a few yards away the rig needs to be disassembled, hauled to the next pad and then reassembled. This entire process can be time and labor intensive not to mention costly to both the company and the environment.

“Pad drilling allows producers to target a significant area of underground resources while minimizing impact on the surface,” states the U.S. Energy Information Administration (EIA). “Concentrating the wellheads also helps the producer reduce costs associated with managing the resources above-ground and moving the production to market.”

Multi-well pad drilling has “played a linchpin role in opening up capital-intensive tight formation oil plays  . . .  as part of a broader revolution in drilling and completion techniques,” according to Richard Mason, Chief Technical Director for industry publisher Hart Energy. “Pad drilling enabled the industry to employ factory-like economies of scale to shorten cycle time and increase rig productivity so that hydrocarbons are brought to market more quickly or, in the case of batch completions, in greater volume.”

Two innovations in the oil & gas sector are driving the market for multi-well drill pad technology: horizontal drilling and hydraulic walking systems.

Game-changer: horizontal drilling

Advancements in horizontal drilling is a close second to hydraulic fracking in terms of the technologies behind the increased levels of crude oil production in the United States and Canada over the past decade. The EIA recently reported that increasing nationwide oil production over the last few years has been largely driven by new shale oil well production which accounted for 54 percent of the country’s overall oil production in 2017. According to the EIA, higher productivity can be linked to growing use of hydraulic fracturing and the increased drilling of longer horizontal wells, which have brought down costs sharply.

Horizontal drilling has reduced the amount of time it takes to drill wells and is especially suited to unconventional oil plays such as shale, Leonard D. Jaroszuk, President and CEO of  Enterprise Group Inc (TSX:E), told INN. “Well pockets can have multiple zones at various depths, the product in the ground can be extracted from multiple points horizontally or side pockets that may have been missed in past single well sites.” Enterprise Group provides access to specialized, high-end technology and equipment for companies in the energy industry.

Majority of multi-well pad drill rigs designed with a hydraulic walking system

“One of the industry’s more recent innovations, pad-to-pad moves, underscores the efficiency gains from rig mobility and pad drilling,” according to the EIA. These pad-to-pad moves were made possible by the advent of hydraulic walking systems, or walking rigs, which were first employed in shale operations in 2004.

Walking rigs are equipped with hydraulic rams that lift the drill rig and a track system that moves the rig to another location. This technological advancement allows companies to transport fully-assembled drill rigs from pad to pad without the cost and loss of productivity associated with rigging down and rigging back up. Drill rigs that can walk themselves to the next well site have also led to the design of more efficient and versatile pad configurations, cutting the time needed to drill multiple wells.

While multi-well pads using walking rigs accounted for about 5 percent of wells drilled in U.S. unconventional plays, by 2013 that number had reached 58 percent. “Today the number of these new mobile rigs has surpassed the number of older conventional units,” reported E&P Magazine.

Increasing efficiency, reducing costs and minimizing environmental footprint

The idea for onshore pad drilling has its roots in offshore drilling operations, where multiple direction wellbores are drilled from one platform. The advent of horizontal drilling coupled with improved rig mobility made possible by hydraulic walking systems allows companies to drill multiple wells (as many as five to ten) going in different directions from a single pad at surface—targeting several formations from a central location—while at the same time reducing both operational and environmental costs.

Pad technology allows companies to split containment and completion costs across multiple wells. “Multi-well pads lower site moving costs and improve efficiency as equipment is used on the same site for multiple wells and projects. This method drills several wells horizontally on one large pad rather than a vast number of singular wells spaced out across the frontier,”Jaroszuk told INN.

Rigs can be mobilized within a matter of hours rather than days, and only one pipe line is needed for multiple wells at one site, rather than a pipeline for each single well location. “A large and long-time client of ours, that is working in the Montney formation of Alberta and BC, has seen significant increases in downhole production and efficiencies in site costs over the years after transitioning from single well sites to multi-well pads. These benefits have played a big role in further implementation of multi-well pads,” said Jaroszuk. “We have grown alongside
this shift and have adapted and built our equipment to facilitate these pad site requirements and efficiencies.”

While a single pad can house as many as 10 to 12 wells, oil companies are finding the “sweet spot” is between four and six wells per pad. According to a report by Transparency Market Research, the multi-well pad market is forecast to expand significantly by 2025 with much of that growth being “dominated by the less than 6 pad size.”

Drilling multiple wells from one location also has environmental benefits in that it causes significantly less surface disturbance and means less road construction and less truck traffic—which translates into decreased diesel emissions. “Accessing multiple wells at one location also minimizes the environmental footprint because significantly less land surface is disturbed. Companies only need to build one road to a multi-well pad, whereas single well locations each need their own road access,” explained Jaroszuk.

The Takeaway

Multi-well pads, horizontal drilling and walking rig technologies have allowed the North American shale oil producers to compete as leaders in the global markets. With the growing demand for energy and fuel, that trend is likely to continue as US and Canadian oil companies find more ways to maximize production efficiencies through cost-cutting technologies.

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some shale related techs that will bring costs down, increase production etc:

 

Dow recognized for resin-coated proppant helpful to shale oil

A special proppant designed by Dow for the shale oil and gas industry helped the Michigan chemical giant earn a prestigious Edison award. The awards are given every year to honor excellence in innovation. Dow’s trademarked VORARAD downhole sequestration technology earned a silver award.

According to Dow, the resin-coated proppant can inhibit harmful isotopes, like radium, from rising to the surface, which aides in minimizing the amount of naturally occurring radioactive material that is brought to the surface during flowback production.

The coated sand is able to trap Radium particles downhole and also create a stronger network of frack matrices by limiting the amount of sand that can travel back to the surface after pressure

pumping is complete and a well is on production.

Dow’s lab tests on the material show that it can reduce Radium in isotopes of water by as much as 65 percent.

The ability of the resin-coated sand to stay secure downhole also helps to reduce pipe and pump blockage.

In addition to the resin-coated sand product created for the unconventional oil and gas industry, Dow was also recognized for work creating better photovoltaic elastomers, packaging material, ecofriendly coloring for cottons, and heat-resistant packaging.

Being recognized with an Edison Award has become one of the highest accolades a company can receive in the name of innovation and business, the awarding entity explained. “The awards are named after Thomas Alva Edison (1847 to 1931) whose inventions, new product development methods and innovative achievements that changed the world, garnered him 1,093 U.S. patents and made him a household name around the world.”

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Emerson's IoT system enhances shale oil production, monitoring

A new technology offering created by Emerson could use data and IoT to optimize production in existing unconventional wells and also help with new well designs. Brian Blakey, director of business development for Emerson’s E&P Software segment, recently outlined the company’s cloud-based system they call the Paradigm K.

The software is a native-to-the-cloud system that is reliable and secure across all platforms. Using a unique algorithm and data set created by surface and subsurface data, the K can help with optimizing current production over the life of a well and help engineers design production and flowback schedules for new wells.

With the K, “any oilfield instrument can now be enhanced with subsurface information to enrich

the measurements they provide,” Blakey said, “extending their application across all physical domains including facilities, wells, fractures, reservoirs,” all of which can be tied to historical, real-time or forecasted data.

The system models the oilfield as one large system and doesn’t separate surface equipment and variables from downhole pressures or permiability factors. Because it is connected to the cloud, it can run simulations in minutes rather than hours or days. The system can also connect to exsiting sensors and incoroporate stored data or live-data streams to create simulations or produce production optimization plans for things like gas injection on a producing well.

The major purpose of the system is to run in the backround and montior operations, looking for unique events that need to be dealt with, Blakey said.

“Rapid changes in unconventional wells can be monitored and optimized,” he said. “We can assure maximum production performance off of only one month’s worth of production data.”

To learn more about the system and how it impacts equipment operations, allocation and fiscal metering, Emerson has put out a webinar.

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(edited)

In Terms of the Bakken

The phrases, words and terms that reveal the evolution of the Bakken. From energy corridors to long-reach laterals, the Bakken shale play has fostered the growth and use of industry phrases that now define the U.S. These are the most important.

From North American Shale Magazine's 2019 Bakken Report: 

Tim Wallace believes the shale energy services industry is on a path to make better use of data to improve performance, much like artificial intelligence applications with predictive analytics and IBM’s Watson computer. The Bakken shale play has evolved from an undeveloped unconventional oilfield into a globally recognized hydrocarbon producer capable of impacting world markets. At one time, the play consisted of only a handful of wildcatting operators and pioneering energy service firms willing to invest time and money into drilling and hydraulic fracturing technology unproven in the region—or anywhere else in the world. From the early days of Hail Mary fracks in Eastern Montana to the Parshall field to the latest iteration of the Bakken, the Williston Basin’s most-important geological formation has supplanted its place in the energy history of the world. In doing so, the Bakken has revealed itself as a massive, light, tight-oil-producing shale formation capable of yielding more than one million barrels of oil per day.

the general public with a never-ending vocabulary list capable of defining the Bakken at the particular time during which a phrase or term was spoken or referenced most prominently. Understanding the evolution—including the past and the near-term future—of the Bakken means understanding the time-linked terminology of the play.


Words From the Well Pad

Held By Production
From the mid-2000s to 2013, the Bakken’s rig count rose dramatically before stabilizing in the high hundreds. Knowledge of the Bakken formation’s possibilities as an oil producer were well-documented and the play was creating unprecedented oil and gas production, construction and workforce opportunities in the areas most targeted. The success rate on a new well horizontally drilled and hydraulically fractured in the Middle Bakken formation of the greater Williston Basin was nearly 100 percent. As small-, mid- and large-scale operators rushed to secure future drilling and production rights throughout western North Dakota and eastern Montana, the play yielded a three-letter acronym capable of summing up this era of the Bakken’s evolution: HBP (Held-By-Production).

To secure drilling rights and future production opportunities, E&P’s needed to secure their lease rights on contracted acreage. Doing so required the operators to drill at least one producing well on their contracted acreage within a specified period from the lease signing (typically three years), to avoid violating the terms of the lease, and jeopardizing the validity of the lease. “When you are scrambling to get a lease Held By Production, you kind of put economics on the back burner,” said Ken DeCubellis, the acting CEO in 2013 for non-operator Black Ridge Oil & Gas.

During the time of HBP activity, operators paid higher prices per hour to keep a drilling rig spudding wells. Less-efficient, older rigs remained in service to keep up with demand. The HBP era was the end of a time when services and strategies were less focused on efficiency and cost-savings and guided instead on securing a future at any cost.

Infill Development
After most of the Bakken’s acreage was HBP’ed and operators had the opportunity to focus more on developing—rather than securing—what they had, most began proving out and delineating the possibilities. Infill development was a term used to explain the strategies of operators as they looked to place future wellbores into specific geographical zones and specific and horizontal lateral lengths. Those focusing on infill development were those capable of moving past the initial rush to secure acreage. Infill development spawned several innovative drilling, completion and production strategies that are still deployed in shale fields across the U.S.

Multiwell Pad Drilling
The success of the infill development era in the Bakken was made possible due in large part due to multiwell pad drilling. Because operators no longer had to drill a single well on a lease and then move a rig to another lease also waiting to be HBP’ed, operators could leave a drilling rig on a single pad longer. The practice allowed for multiple wells to be placed on a single pad. Pads started to get bigger and more elaborate. Walking drilling rigs capable of deploying hydraulic lifts to move the rig from one spud hole to another greatly decreased the time it took to go from one wellbore to two wellbores on a single pad. From a single pad, operators learned they could place multiple wells and target the same, or different formations while still giving them the ability to effectively drain their reservoir through methods available at the time.

Energy Corridors
The North Dakota Department of Mineral Resources created the first-ever energy corridors. The term was used to describe a top-surface geographic orientation that maximized industry’s access to well sites while minimizing their presence on the landscape. Spacing units that once showed random wellbore lines running in all directions and at different lengths transformed into more unified images showing wells running in unison in a single direction. North Dakota energy leaders utilized 1,280-acre spacing units to create a uniform pattern of development that helped with pipelines, electrical lines and traffic patterns.

Decline Curves
With each new operational advancement in the field, every well has become better and holds more promise than previous versions. The advancements could be linked to drilling more precise wellbores or fracturing more of the reservoir through new technology or approaches, but either way, decline curves have been a topic since the early days of the Bakken. Operators, analysts and investors all like to talk about how fast a well will decline in production. The initial production rate (linked to a period like 30 days or 3 months) is continuously rising in the Bakken. Decline rates have also risen, showing that new fracking and drilling techniques are making wells produce more oil at higher rates over a longer period.

Long-Reach Laterals
In the early development of the Bakken formation, most laterals were drilled to 8,000 feet or less. By the time engineers and investors were referring to long-reach laterals, the length of a lateral had changed. Most long-reach laterals placed in the middle Bakken today extend to three miles or roughly 13,000 feet. More efficient drilling bits, extended-reach coiled-tubing spools and more powerful drilling rig systems now allow operators to drill longer laterals, which they say can produce more oil from a single well.

Flaring
Often misunderstood as a practice of wasting or getting rid of unwanted associated gas produced during the oil retrieval process, the term flaring drew national attention to the Bakken. Still a challenge that operators deal with today, flaring has referred to the venting of associated gas that takes place due to inadequate or a lack thereof of takeaway or gathering infrastructure. Technology creators, midstream companies, investors, policy makers and the public have all played a strong role in the usage of the term. In the early development days of the Bakken, flaring was common across the play and more than two-thirds of all gas produced in the play was flared. Today, infrastructure has been installed to take away gas streams in accessible locations. For the remote and hard-to-reach areas of the Bakken, technology providers have created economically feasible options to capture and remove associated gas from the play.

Spud-To-TD
Advancements in mud motors, drill bit materials and strategies to reach total depth on a well have come a long way. In the early days of the Bakken, a drilling rig crew typically required 45 to 60 days to drill an 8,000-foot well from spud (the surface hole) to the toe of the horizontal (total depth). The term became important and often referenced when the drilling rig count declined in the Bakken and other U.S. shale plays while production and activity levels remained. The U.S. Energy Information Administration also began tracking drilling rig counts and how efficient the rigs in each play were as the Spud-to-TD times fell across the U.S.

DUCs
From late 2014 through 2017, the Bakken experienced a major decrease in activity due to low oil prices. Operators were unable to continue at their planned activity levels and had to pull back certain operations. Many began holding off on completing wells that had been horizontally drilled and were waiting to be hydraulically fractured before going on production. Research analysts began tracking the number of DUCs, or wells that were drilled but uncompleted. The state of North Dakota did the same. Some operators had to choose whether to invest or continue with a drilling contract and drill new wells, or spend their money completing wells. DUCs are still tracked today but have less prominence in the national context of shale oil production.


Words Away From the Wellhead

Crude-By-Rail
Oil takeaway capacity via any means has always been an issue in the Bakken. As the Bakken’s production grew from the mid 2000’s to now, there has always been a disproportionate amount of takeaway infrastructure—pipeline, rail or truck—to match the supply from the play. Between 2013 and 2016, one of the prominent means to move Bakken oil to the East or West Coast was via rail. The reference to the transportation style helped advance the tank car specifications used to move oil across the country. Investors tracked the usage of crude-by-rail and the practice spawned the growth and importance of another Bakken staple.

Transload Facilities
The geographic sprawl of the Bakken puts wells in remote locations that are tough to get to or take a long time to return from to a major community. Transload facilities started to rise in popularity as the play developed. Operators, midstream firms and construction or logistics teams needed to more-efficiently and economically bring in and store equipment, goods or materials. Several facilities grew to offer sand storage, piping and casing yards and oil storage or offtake infrastructure connected via pipeline to larger pipelines running out of the region.

Saltwater Disposal Wells
Like most shale plays, the Bakken system produces high volumes of saltwater brine during production. SWDs, or saltwater disposal wells, have grown in existence throughout the play. Wells are drilled into the Dakota formation where produced water is injected underground or stored at a SWD facility.

Lower-For-Longer
At the start of the oil price downturn at the end of 2014, investors, analysts, oil price predictors and oil company executives all used the phrase lower-for-longer to insinuate which direction they believed oil prices would head in the months ahead. The term was present in the shale world’s lexicon for roughly two-and-a-half years and brought on another term.

Breakevens
As operators began to find ways to maintain operations, workforce numbers and production numbers, the term breakeven was introduced into the Bakken scene and has been referred to ever since. Investors, operators and service companies all began to explain their breakeven costs. The term refers to the price point oil has to trade at for the investment of an oil well, service or operation to keep the company from losing money. Breakeven price numbers were estimated for geographical regions of the Bakken and were impacted by several factors, including infrastructure availability, lease operating expenses, and the initial rate of return a company was willing to take at any given oil price.

Cash Flow
With investors now looking to benefit from previous investments into shale energy production companies increasing, many oil and gas production executives are telling the industry that their plan for operation will remain within cash flow. Before the current investor push, operators were willing to outspend their yearly cashflow by taking on debt to drill and frack new wells. The goal was to grow production. Today, with a push to please investors, operators are focused more on operating within cash flow and limiting operations based on the amount of money they have generated from existing operations.

Two Million Barrels
The main trend over time for Bakken oil and gas production is associated with increases. The Bakken formation, which currently accounts for nearly 95 percent of all the oil produced in North Dakota, has been pumping out more than 1 million barrels of oil per day for several straight years. Government officials and industry have both pushed for the Bakken players to continue the production increase trend in the coming months and years and work to surpass 2 million barrels per day.

~From The Bakken Report 2019 print issue

Edited by ceo_energemsier

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Hess Produces Record-Breaking Test Well In Williston Basin

Oil Patch Hotline
Thu, 05/02/2019 - 10:09

Hess Corp. has produced a record-breaking 24-hour test well this month in McKenzie County, N.D., surpassing all records for U.S. land wells, according to an article in the website of the Oil Patch Hotline, an oil and gas trade publication for the Williston Basin.

“This was a barn burner,” said Hotline Publisher Dennis Blank. “The highest IP tests recorded before this on new horizontal Bakken wells were in the range of 3,000 to 4,000 barrels of oil equivalent per day.”

Hess said the An-Bohmbach-153-94-2734H set a new record 24-hour IP at 14,662 boe/d. The well produced 10,169 barrels of crude oil and 26,960 Mcf of natural gas and is located in Sec. 22, T153N-R94W. This new record breaker followed an earlier April 5 record of 10,626 boe/d on a companion horizontal well in the same pad.

“It was a great well and a great result,” said Hess President Greg Hill. “We achieved a very high rate IP, and it confirmed that our acreage performed very strongly in comparison to other operators.”

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Current Characteristics of Bakken Well Completions

As the well count in the Bakken or Three Forks shale formations continues to grow, the strategies deployed to hydraulically fracture each new well have changed when compared to previous approaches.
 
As the well count in the Bakken or Three Forks shale formations continues to grow, the strategies deployed to hydraulically fracture each new well have changed when compared to previous approaches. A combination of factors has helped usher in a new fracture design and strategy used by many of the operators nearly every six months for the past several years. New mechanical downhole technology used to perforate and then plug a portion of the wellbore off allow for more precise puncture placements into the wellbore. Dissolvable material, referred to as a diverter, is being widely used to section off parts of a fracture network for a specified period, all to ensure each section of a wellbore gets its desired attention from perfs or proppant and isn’t compromised when other sections are getting fracked. Downhole analytics and data sets are being captured through fiber optic cable. And, petroleum geologists continue expanding on their ever-evolving understanding of the
rock at the micro level. All of these factors are also present during a time when many new wells in the Bakken and Three Forks formation are infill wells placed on an existing pad or next to a parent well previously drilled, fracked and brought onto completion.

The interplay between the parent well and the child, or infill, wells has nudged engineers and completion consultants to factor in the effects of placing and then stimulating a wellbore close to an existing wellbore. Despite the new matrix of factors impacting the overall effectiveness of a typical Bakken frack design, Bakken and Three Forks wells are surpassing previous production expectations by continuing with a focus on fracture optimization.

Optimized Completions Unlock Bakken Value
Continental Resources, one of the largest Bakken producers to date, has reported a noticeable uptick in well production from 2011 to the present. The uptick is based on a combination of well placement and better frack jobs. In early 2018, Continental put three wells into its all-time top five producers list because of optimized completions. Each of the three wells averaged more than 1,500 barrels of oil per day for the first 30 days.

The completion changes by Continental have also produced better returns per well. In 2011, a Continental well drilled and completed at an oil price of $65/b would yield a rate of return (ROR) of roughly 15 percent. By 2018, Continental was reporting a 140 percent difference from 2011. A well drilled and completed at $65/b yields a 140 percent ROR. For Continental and several other major operators, the focus on optimized completions has pushed the boundary of the core of the Bakken. Some operators now consider the core much larger than previously thought when new completion designs are deployed.

Marathon Oil Corp. has expanded its core acreage using area-specific completion designs. A four-well pad in Marathon’s Ajax area located in Dunn County, North Dakota, produced roughly 2,400 barrels of oil equivalent for the first thirty days. “Strong early results in the Ajax mark another important step forward in our ongoing efforts to extend the core of our Bakken acreage position,” said Lee Tillman, president and CEO of Marathon. “Through enhanced area-specific completion designs, and a lot of hard work from our Bakken team, we continue to meaningfully uplift the quality of our inventory.”

Committed To The Next Generation Of Completion Design
No Bakken operator has touted its success with fracture design enhancements in the Williston Basin more than Whiting Petroleum. The operator believes it has always been ahead of the competition with testing and deploying new designs and methods. This year Whiting announced it was now using its Generation 5.0 design approach.

The new approach centers around the idea of optimizing the completions to the well spacing and geology of each individual well. For infill wells the strategy is to concentrate more of the stimulation near the infill wellbore, lower the amount of sand used, place more entry points and use more diverter material. For wells further away from other wellbores, Whiting looks to create a mix of far-reaching fractures and near-wellbore concentration while using more sand, fewer entry points and diverter material to ensure all entry points are connected.

No matter the well, Whiting now builds calibrated models for every area, uses multivariate analysis to understand which completions factors impact production most and then works with service companies to ensure they have the latest technology. The main factors Whiting focuses on with new wells is entry points, frack stages, total fluid, proppant, diverters and lateral length.

Investing In The Frack
In early 2018, shale pioneer Liberty Oilfield Services issued an IPO. The fracture design and pressure pumping experts at Liberty have shown how profitable and important the fracturing segment of shale, the Bakken included, can be.

While Liberty has been providing returns to shareholders, it has also continued investing in its suite of fracture-related products. The company has created a proprietary and trademarked FracTrends database that includes results from more than 60,000 wells along with analysis tools. Another trademarked product Liberty calls Fraconomics, allows clients to use big data to find ways to lower a cost of a barrel of oil. To help customers in close proximity to populated areas, Liberty has created a Quiet Fleet that features technology designed to minimize noise pollution created during pressure pumping operations. And, along with last-mile logistics for proppant-to-well timing, the company has also partnered with CAT to provide predicative maintenance management on equipment at the well site. Liberty’s focus isn’t just on the strategy for proppant placement or the use of diverters. The company now tracks, to the minute, the efficiency and activity of its frack fleets. Doing so helps the company greatly reduce client non performing time.

Next Gen Frack Firms On The Way
In addition to the constant research and roll-out of tooling and proppant by major energy service firms, the evolution of the fracking sector has spawned several new firms designed to meet the needs of the modern market.

Axis Energy Services represents a group of companies working to give operators more options with modern well designs and longer lateral lengths. “For too long, E&P companies in the U.S. have had two choices for completions. They could use coiled tubing with reliability issues in longer laterals, or stick pipe requiring too many companies on site—often without the right equipment or crews,” said Wendell Brooks, CEO. “The mission of Axis is simple: to offer our customers a third option to reach new levels of efficiency.”

John Schmitz, executive chairman for Axis, has also discussed the changing face of shale. “As the shale revolution enters the phase of capital efficiency and manufacturing growth, operators can’t afford to have legacy business plans and equipment slow them down or eat into their returns,” Schmitz said. “We formed Axis based on listening to our customers on the new business model and new equipment needed to get wells to production optimally and quickly.”

Lime Rock Partners, a group linked to several shale plays including the Bakken, was an investor in Axis. The company uses data to determine drill-out times prior to starting the process and has new workover rigs and completion specialists focused on optimizing completions for long-lateral shale wells.

To reduce the always-present challenge of frack hits between parent wells and infill wells, Reveal Energy Services has created a new product called FracEye. The system allows operators to make timely adjustments to wells being fracked on multiwell pads that feature parent and child wells. The system categorizes the type and severity of interwell communication by measuring the pressure response from a parent well as hydraulic fracturing proceeds normally in child wells. Geoscientists and completion engineers can use the data to determine if, or to what severity, a frack hit is taking place. The system looks for direct fluid transport from wellbore to wellbore, fluid migration increases, instantaneous pressure response in an offset well or, hopefully, if there is no signal of pressure change in a neighboring well.

Austin, Texas-based Seismos received $10.5 million from investors to harness a software-based technology to also better understand frack hits. Through its product Seismos-Frac, engineers can adjust treatment solutions on the fly. The technology was developed in conjunction with Stanford University faculty.

National Lab Frack Attention
At the national level, several research institutions from the University of North Dakota’s Energy and Environmental Research Center to Oak Ridge National Lab continue to assess, test and research novel or intricate methods to better understand the future of fracking.

Oak Ridge researchers are using a combination of neutron and x-ray scattering to make fracking more efficient. The team is testing the possibility and effectiveness of introducing ultrasonic (acoustic energy) to the downhole rock prior to fracking to increase porosity and permeability once the stimulation takes place.

“It's all about supplying energy into the formation to release hydrocarbons,” explained ORNL researcher Joanna McFarlane.

“Think of a sponge filled with water,” Richard Hale, another ORNL researcher added. “The water doesn’t come out of the pores until you squeeze it. Acoustic energy is really, really good at squeezing these pores. In small core sample–size experiments placed in acoustic baths, we can see the oil flows easily and rapidly from the rock.”

Ultrasonic techniques have previously been used to clear debris near the surface of a well. ORNL researchers believe the same technique might be applicable 8,000 feet below the surface.

A team of researchers at Los Alamos National Lab believe shale stimulation will benefit from understanding previous tectonic movements and water seepage forces not previously considered. A mathematical model shows how branches form off vertical cracks along the wellbore during the fracking process. Further research, they believe, will help engineers better understand how to optimize fracture pumping rates and the viscosity of the fluids pumped.

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Permian Firm Aims for 25-percent Headcount Growth

The energy services firm Wood has ambitious employee growth plans this year in the Permian Basin.

“If we haven’t created 500 new jobs in West Texas by the end of the year, I’ll be disappointed,” Andrew Stewart, CEO for Americas Asset Solutions with Wood said Tuesday on the sidelines of the 2019 Offshore Technology Conference (OTC) in Houston.

Approximately one-half of Wood’s approximately 4,000 employees based in U.S. shale basins work in the Permian, where the company is engaged in various pipeline, power and even solar projects in the region. Stewart said that the firm currently is advertising for more than 100 craft professionals, and he noted that the company is looking to hire employees – who would receive full benefits packages. Some of the specialties the company is recruiting for include operations and maintenance specialists, mechanical fitters, instrumentation pros, welders and others.

“Sixty percent of our payroll is craft professionals,” said Stewart. “Everything that’s been built and designed has to be maintained.”

Although Wood has had a presence in the Permian for more than two decades, the company – like other energy services firms – has reported strong growth in the region. In fact, Kerry Sedge – Wood’s communications director – confirmed  that Wood’s headcount and revenue growth in 2018 outpaced general production growth in the basin.

Wood, which has long specialized in designing and building pipelines and shale facilities, is also branching out its engineering, procurement and construction (EPC) capabilities. Stewart pointed out the company is diversifying its expertise to include power projects (solar and co-generation), fabrication and operations and maintenance. Some of the firm’s customers include operators such as ExxonMobil unit XTO, Anadarko and Shell as well as midstream players such as Navitas.

Sedge also noted that Wood is adding a digital element to its Permian service offerings. She explained that the firm is developing a “CoLab” facility in Houston that will integrate virtual reality, data analytics, automation and control robotics, process optimization and asset integrity, block chain and cyber Internet of Things and other systems and tools.

Stewart pointed out that Wood’s increasingly diverse client base, coupled with various digitalization components, should enable employees to enjoy more career continuity by developing their skill sets across a “rich variety” of projects.

“We want to be the employer of choice by having employees have a career basis rather than a project basis,” he concluded.

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19 hours ago, Douglas Buckland said:

I have a question for you...

Why do the major players who are moving into the Permian, and other shale plays, think they can make it work any better than the small or mid cap outfits?

It does not matter who owns or drills these wells, the drastic decline curves, lack of pipeline capacity, lack of experienced personnel and the available technology remains the same.

From my perspective, they have deeper pockets, which will simply allow them to bleed longer.

Furthermore, with their top heavy organizations, bloated HR and HSE departments and their process driven organizations (if it is not in the manual you will not do it, no innovation or thinking out of the box allowed), their overhead is much greater than the smaller operators and their cost/bbl higher.

The big outfits do NOT have any magical new technology available to them. The technology is generally advanced by the service companies and is available to anyone willing to pay for it.

So again, why do the big players think they will do better in the shale oil arena?

This somewhat directs towards your statement about top heavy, no innovation and not thinking out of the box being allowed.

 

_____________________________________

 

BP Wants to Simplify the Way Employees Work

Rob Kelly, head of upstream digital for BP, had just come from a data science expo at the company’s Houston office before meeting a group of media professionals at the Offshore Technology Conference Tuesday morning.

During the media briefing, BP executives shared their Modernization and Transformation agenda (M+T = Sustainably Improving Performance + Feel) which they began working on almost three years ago.

BP is looking at M&T in three different areas they describe as:

  • Agility: transforming and simplifying the way we work
  • Digital: transforming how we deliver – digitizing and automating our operations
  • Mindset: transforming the way we think

“The people at the expo were just fascinated by what we’re trying to do to pull that digital organization together,”

He added, “It’s not about doing it in a single place or project or operation. It’s about ‘can we identify something we can then scale, do it in one region and then scale across the 14 regions we have in the world?’ We’re just scratching the surface with the M&T agenda.”

Kelly said BP is trying to deliver value in three months, in which the technology team approves a concept that his team then takes and delivers MVP (Minimum Viable Product) to an asset or facility.  

“For the 18,000 people we have working in the upstream, they’re really looking for ways to make their day-to-day job more fun, more interesting and easier to do. That’s the big positive here,” said Kelly. “It’s trying to make coming to work as enjoyable as being at home.”

Kelly and his team have received feedback about how difficult it is for people to get a hold of the right data to do their jobs.

“It’s in spreadsheets spread all over the place,” he said.

Kelly looks down at his smartphone and scrolls left to right.

“Just like the apps on my phone, which make things so much easier in my home life – you’ve really got to make it as easy as that in the work life. That’s the key,” he said. “I think if we can do that, then we can attract the millennials and the young folks to come in … because that’s what they do, that’s what they like.”

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I'm doing this off my phone, so will be brief.

My point is that the 'shale players' keep aluding to the 'fact' that they are employing leading edge technology in their quest to appear viable. They are not, if anything, they are fine tuning pre-existing technology.

Two points from your reply:

Pad drilling is not new technology. I know for a fact that drilling from pads in Indonesia was being done decades ago.

Searching for pre-existing fracture beds was essential in the Vietnam basement fields at least as far back as 2003.

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1 minute ago, Douglas Buckland said:

I'm doing this off my phone, so will be brief.

My point is that the 'shale players' keep aluding to the 'fact' that they are employing leading edge technology in their quest to appear viable. They are not, if anything, they are fine tuning pre-existing technology.

Two points from your reply:

Pad drilling is not new technology. I know for a fact that drilling from pads in Indonesia was being done decades ago.

Searching for pre-existing fracture beds was essential in the Vietnam basement fields at least as far back as 2003.

Both of those Pad Drilling and fracture mapping are being revisited and improved, greatly improved. New tech of laser application and  combination with seismic creates an unbelievable subsurface imagery. Satellite mapping which wasnt available a long time ago adds further. New softwares and AI techs are making everything much faster and better and yielding breakthrough results. Drilling techs and completions techs are being created each day to cover a-z of oil exploration and production. Did the drilling pads from Indonesia have 6-18 or more subsurface horizontal wells drilled producing from more than 2 or 3 zones?

Fracture mapping has been around, very few use it but the improvements that have been made are great. Fracture mapping has been around since the 40s even not earlier.

You can say the same thing seismic was around a long time ago, so 2D, 3D and 4D are not new techs.

Laser mapping is not new either, and the use of ultrasound and acoustics for fracturing is not new either, or even gel fracturing?

or air fracturing?

To say that use of existing or pre-existing tech is no achievement is false. Then medicine should be antiquated and we shouldnt have all the hitech cell phones, smart phones and what nots, because there used to be the old bag cell phones and the 1 ton brick block cell phone ;)

 

 

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You are missing my point. The shale players seem to take credit for techniques, practices and equipment which they neither invented or developed. What they have done is simply apply it to their specific sets of circumstance. This is routinely done in different geographic locations considering the various reservoir parameters.

I find it a bit shady for LTO operators to spout that 'technology' will solve their problems, in an effort to get funding, when they cannot point to a single 'technology' they have created.

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(edited)

The debate over shale oil has now become polarized like almost every other topic in American society; you are a staunch cheerleader for it, able to completely ignore its dismal economics and financial situation, its massive debt, or you question its sustainability exactly because of its dismal economics and its financial situation. Cheerleaders outnumber skeptics by 1000:1 and much of that has to do with having high paying jobs in the shale oil industry, or getting free royalty from it, loaning money to it, analyzing it and selling the data, renting it porta potties...everybody is trying to make money from it as fast as they can and want to keep the party going as long as possible.

If you are skeptical of shale oil, or for instance in my case, do not believe entirely in its long term sustainable or its grossly over exaggerated reserves, you are essentially un-American, a shale "hater," as opposed to a shale lover, or something really stupid like, anti-oil. 

Make no mistake, shale oil is an amazing resource that the industry has done a great job of unlocking out of some really shitty rock; its jobs are great, it has provided relief at the pump to consumers and helped the economy by lowering trade deficits, etc. etc. What people don't get is that most of that has occurred on debt. Growth thru use of debt is fake, its artificial. And what they really don't seem to get is all these benefits are fleeting; for some reason they think America is floating on the Atlantic Ocean of shale oil. People new to the shale oil phenomena and the oil business in general do not understand nothing lasts very long in the oil biz. The internet, and the never ending hunt for links to support beliefs, has distorted shale oil reality.  

In any case, this technology thing is a useful tool for cheerleaders, it always gives... hope. Sort of like predicting higher oil prices. Tweaking old technology  has really not changed the economics of shale oil very much over the past decade (higher productivity has NOT led to greater profits); now the soup of the day is mass manufacturing and economy of scale, again. Google Encana's work in this regard; they lost their ass 1Q19. Now, of course, majors will save the day and we'll be good for another 50 years.

All this crap about technology is old and its worn out; even the shale oil industry has become realistic about it. Why, for instance, has the shale oil industry not embraced miscible gas injection or huff and puff EOR methods (that are +70 years old, by the way)? Because its NOT economical at current prices.   

Art's right;  http://www.artberman.com/shale-cost-reductions-are-10-technology-and-90-industry-bust/

 

Edited by Mike Shellman
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22 minutes ago, Mike Shellman said:

Make no mistake, shale oil is an amazing resource that the industry has done a great job of unlocking out of some really shitty rock; its jobs are great, it has provided relief at the pump to consumers and helped the economy by lowering trade deficits, etc. etc. What people don't get is that most of that has occurred on debt. Growth thru use of debt is fake, its artificial. And what they really don't seem to get is all these benefits are fleeting; for some reason they think America is floating on the Atlantic Ocean of shale oil. People new to the shale oil phenomena and the oil business in general do not understand nothing lasts very long in the oil biz.

That Statement fairly well says it all. Maybe add a line in here on well longevity to bux spent ??

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(edited)

1 hour ago, Mike Shellman said:

What people don't get is that most of that has occurred on debt. Growth thru use of debt is fake, its artificial. And what they really don't seem to get is all these benefits are fleeting; for some reason they think America is floating on the Atlantic Ocean of shale oil.

 

Debt is what fuels the entire economy, not just shale.  How many people pay cash for their houses?  A car is cheaper than a house but how many people pay cash?  How many people borrow to get a higher education?  Borrow to fund vacations?

Credit is another name for it and it's something you or your company own.  It's your potential value that you are selling forward so that you can have capital to realize that potential.  If you fail to repay the credit then your potential value may have been misjudged but it doesn't make it worthless, just worth less than what you and the lender may have perceived at the start.  

I just bought a mattress last night at Mattress Firm and the guy told me they were in and out of bankruptcy in 45 days.  They still had our records of previous purchases and guess what, they sell mattresses on credit!  I paid for mine with my AMEX that isn't a credit card.  I think you take too much issue with shale because of credit.  The stripper business can't operate without credit either and what happens to stripper companies that get in a cash crunch?  Look no further than our friend up in Canada that just walked away from 4700 wells.

If you don't like debt then you really don't like the economy so you are just a generalized hater in that case.  For you gold is probably the only real money, right?  

For the record, I don't do debt.  I pay cash because I can but even when I couldn't, I saved and paid cash for almost everything.  I purchased a few cars with debt but not many.  We only had a mortgage for 15 years and paid off the last one on our current house back in 2002 after 5 years.  I just don't think the economy as we know it would function without debt.  I ran a cash-flow positive company for 15 years and borrowed money only one time.  Growth was very difficult and without an outside injection of capital, we never got beyond 12 employees but that was fine with me.  

Edited by wrs
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(edited)

I don't "hate" anything, fella. I have no earthly idea what "stripper wells" or stripper well operators have to do with the debate over shale oil economics and finances; clearly you would like to paint me as just a dumb stripper well operator who does not understand big, corporate America...or hates shale oil  because its "raining on my parade," whatever. Its grossly untrue, a weak argument and no basis whatsoever for meaningful debate. You need to get some help with this animosity you have toward stripper wells. Do you feel the same way about small farmers?

Credit/debt has a role in economic growth, of course. Ultimately it needs to be paid back for that growth to be sustainable. Holler when you think $72 trillion of government, corporate and personal debt in America is enough.

Borrowing money to manufacture assets that decline 83% the first 30 months after being put on the shelf requires a lot of discipline to pay that debt back; its way different than borrowing money to build a widget plant where PPE appreciates over time, for instance. Oil and debt has never mixed. The shale oil industry is all puffed up now because of its "free" cash flow (an oxymoron if I ever heard it) but is still replacing reserves, or growing reserves, and not paying debt back. The longer that  goes on, the harder it gets to pay back production debt.  Ask BHP about selling assets down the road to get out of debt. Or PXD, who just took a half billion plus dollar bath on its shale oil assets in the Eagle Ford. Or I know, lets hear what the great "wildcatter,"  Floyd Wilson has to say about selling assets to get out of debt, or Gary Evans, or Tom Ward. All of these terrific shale oil assets you reference are going to be 15 BOPD stripper wells, making lots of water, on rod lift, facing $100K + plugging and decommissioning costs. There's your chance to put your money where your beliefs are. 

I quit. Whatever I say that is factual or evidential you and others will simply attack me for it. Or flood the forum with cherry picked links from the internet. That's pretty much all you guys have got. If asked to model the way out of debt, the way forward for the shale oil industry, so it can deliver what it has promised America, you couldn't do it if you had to. 

 

Edited by Mike Shellman

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3 hours ago, Mike Shellman said:

I don't "hate" anything, fella. I have no earthly idea what "stripper wells" or stripper well operators have to do with the debate over shale oil economics and finances; clearly you would like to paint me as just a dumb stripper well operator who does not understand big, corporate America...or hates shale oil  because its "raining on my parade," whatever. Its grossly untrue, a weak argument and no basis whatsoever for meaningful debate. You need to get some help with this animosity you have toward stripper wells. Do you feel the same way about small farmers?

Credit/debt has a role in economic growth, of course. Ultimately it needs to be paid back for that growth to be sustainable. Holler when you think $72 trillion of government, corporate and personal debt in America is enough.

Borrowing money to manufacture assets that decline 83% the first 30 months after being put on the shelf requires a lot of discipline to pay that debt back; its way different than borrowing money to build a widget plant where PPE appreciates over time, for instance. Oil and debt has never mixed. The shale oil industry is all puffed up now because of its "free" cash flow (an oxymoron if I ever heard it) but is still replacing reserves, or growing reserves, and not paying debt back. The longer that  goes on, the harder it gets to pay back production debt.  Ask BHP about selling assets down the road to get out of debt. Or PXD, who just took a half billion plus dollar bath on its shale oil assets in the Eagle Ford. Or I know, lets hear what the great "wildcatter,"  Floyd Wilson has to say about selling assets to get out of debt, or Gary Evans, or Tom Ward. All of these terrific shale oil assets you reference are going to be 15 BOPD stripper wells, making lots of water, on rod lift, facing $100K + plugging and decommissioning costs. There's your chance to put your money where your beliefs are. 

I quit. Whatever I say that is factual or evidential you and others will simply attack me for it. Or flood the forum with cherry picked links from the internet. That's pretty much all you guys have got. If asked to model the way out of debt, the way forward for the shale oil industry, so it can deliver what it has promised America, you couldn't do it if you had to. 

 

Hi Mike,

I agree with most of what you say.  If future prices are higher (similar to the EIA's AEO 2018 reference oil price case), then for the Permian basin oil companies debt may be paid back.  Cumulative net revenue in the scenario below is assumed to be zero in Jan 2010 in the scenario below and well cost is $10 million in 2017$, interest rate is assumed to be an annual rate of 7% (at 2.5% inflation rate), annual discount rate is assumed to be 10%.  Note also I have assumed no revenue from natural gas sales and LOE is a bit low to account for this omission.  You are correct that we don't know future oil prices, but my expectation is that they will be at least as high as the EIA's AEO reference case. If oil prices follow the low scenario in the oil price chart below, then the Permian basin will not ever be able to pay off its debt if the assumptions of my model are correct.

permian1902decl14.png

aeo oil price.png

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Dennis, I've seen this 45 times, thanks. I am unclear what you mean by "Permian" debt and what the difference is say between it and other shale oil basin debt that folks like Pioneer, Devon, Anadarko, Whiting, QEP, etc. carried with them to the Permian from other basins. Are you just picking a debt number out of the air? How about equity, are you including that? As in lost shareholder equity, retained earnings, equipment, hedge losses, transportation volume commitments, default on drilling contracts, etc., the difference in estimated reserves v. actual reserves less all costs, tax deferments, etc., how does the shale oil industry pay all that back at $60 gross WH prices? Because that is what those prices are today. The EIA has never gotten oil prices right, not ever. 

Debt to exaggerated reserve assets are suspect now, what makes you think that will get better as reserve inventory is drilled off? What happens when impairments become necessary, more than they already are necessary? A ton of stuff should have already come off the books but for the saving graces of the SEC. Where do you think lenders would be if all LTO reserves had to be re-appraised? OXY just got sent to the junk pile because of its new debt to EBITDA ratios.  Loan covenants have restrictions on leverage and already ARE causing reduction in CAPEX, which in turn make your growth models NA. 

165% ROI's over 15 years, at best, are not sufficient to replace reserves and pay back debt/equity, not at anything below about $80. You are an economist, and oil analyst, get some of these "oil men" here to pardnor up with you and get in the shale biz. Its a piece of cake. With the right technology you'll make a fortune. 

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Permian shale output closes gap with Saudi Arabia as rig count doubles, confirming US’ powerhouse status

 

  • Exxon’s 1.6 million acres in the Permian means it can approach the field as a “megaproject”
  • The majors’ Permian investments position the field to compete with Saudi Arabia as the world’s top oil-producing region

NEW MEXICO: In New Mexico’s Chihuahuan Desert, Exxon Mobil Corp. is building a massive shale oil project that its executives boast will allow it to ride out the industry’s notorious boom-and-bust cycles.
Workers at its Remuda lease near Carlsbad — part of a staff of 5,000 spread across New Mexico and Texas — are drilling wells, operating fleets of hydraulic pumps and digging trenches for pipelines.
The sprawling site reflects the massive commitment to the Permian Basin by oil majors, who have spent an estimated $10 billion buying acreage in the top US shale field since the beginning of 2017, according to research firm Drillinginfo Inc.
The rising investment also reflects a recognition that Exxon, Chevron, Royal Dutch Shell and BP Plc largely missed out on the first phase of the Permian shale bonanza, while more nimble independent producers, who pioneered shale drilling technology, leased Permian acreage on the cheap.
Now that the field has made the US the world’s top oil producer, Exxon and other majors are moving aggressively to dominate the Permian and use the oil to feed their sprawling pipeline, trading, logistics, refining and chemicals businesses. The majors have 75 drilling rigs here this month, up from 31 in 2017, according to Drillinginfo. Exxon operates 48 of those rigs and plans to add seven more this year.
The majors’ expansion comes as smaller independent producers, who profit only from selling the oil, are slowing exploration, and cutting staff and budgets amid investor pressure to control spending and boost returns.
Exxon CEO Darren Woods said on March 6 that Exxon would change “the way that game is played” in shale. Its size and businesses could allow Exxon to earn double-digit percentage returns in the Permian Basin even if oil prices — now above $58 per barrel — crashed to below $35, added Senior Vice President Neil Chapman.
Exxon’s 1.6 million acres in the Permian means it can approach the field as a “megaproject,” said Staale Gjervik, head of shale subsidiary XTO Resources, whose headquarters was recently relocated to share space with its logistics and refining businesses. The firm also recently outlined plans to nearly double the capacity of a Gulf Coast refinery to process shale oil.
“It sets us up to take a longer-term view,” Gjervik said.
The majors’ Permian investments position the field to compete with Saudi Arabia as the world’s top oil-producing region and solidifies the US as a powerhouse in global oil markets, said Daniel Yergin, an oil historian and vice chairman of consultancy IHS Markit.
“A decade ago, capital investment was leaving the US,” he said. “Now it’s coming home in a very big way.”
The Permian is expected to generate 5.4 million barrels per day (bpd) by 2023 — more than any single member of the Organization of the Petroleum Exporting Countries (OPEC) other than Saudi Arabia, according to IHS Markit. Production this month, at about 4 million bpd, will about double that of two years ago.
Exxon, Chevron, Shell and BP now hold about 4.5 million acres in the Permian Basin, according to Drillinginfo. Chevron and Exxon are poised to become the biggest producers in the field, leapfrogging independent producers such as Pioneer Natural Resources.
Pioneer recently dropped a pledge to hit 1 million bpd by 2026 amid pressure from investors to boost returns. It shifted its emphasis to generating cash flow and replaced its CEO after posting a fourth-quarter profit that missed Wall Street earnings targets by 36 cents a share.

FASTFACTS

5.4 million

The Permian Basin is expected to generate 5.4 million barrels of oil per day by 2023, more than any single OPEC member other than Saudi Arabia.

Meanwhile, Shell is considering a multibillion-dollar deal to buy independent producer Endeavor Energy Resources, according to people familiar with the talks. Shell declined to comment and Endeavor did not respond to a request.
Chevron said it would produce 900,000 bpd by 2023, while Exxon forecast pumping 1 million barrels per day by about 2024. That would give the two companies one-third of Permian production within five years.
At first, the rise of the Permian was driven largely by nimble explorers that pioneered new technology for hydraulic fracturing, or fracking, and horizontal drilling to unlock oil from shale rock, slashing production costs. The advances by smaller companies initially left the majors behind. Now, those technologies are easily copied and widely available from service firms.
Surging Permian production has overwhelmed pipelines and forced producers to sell crude at a deep discount, sapping cash and profits of independents who, unlike the majors, don’t own their own pipeline networks.
Even as the majors have ramped up operations, the total number of drilling rigs at work in the Permian has dropped to 464, from 493 in November, as independent producers have slowed production, according to oilfield services provider Baker Hughes.
Shell, by contrast, plans to keep expanding even if prices fall further, said Amir Gerges, Shell’s Permian general manager.
“We have a bit more resilience” than the independents,” he said.
In west Texas, the firm drills four to six wells at a time next to one another, a process called cube development that targets multiple layers of shale as deep as 8,000 feet.
Cube development is expensive and can take months, making it an option only for the majors and the largest independent producers. Shell has used the tactic to double production in two years, to 145,000 bpd.
The largest oil firms can also take advantage of their volume-buying power even if service companies raise prices for supplies or drilling and fracking crews, said Andrew Dittmar, a Drillinginfo analyst.
“It’s like buying at Costco versus a neighborhood market,” he said.
The majors’ rush into the market means smaller companies are going to struggle to compete for service contracts and pay higher prices, said Roy Martin, analyst with energy consultancy Wood Mackenzie.
“When you’re sitting across the negotiating table from the majors, the chips are stacked on their side,” he said.
The revival of interest in the Permian marks a reversal from the late 1990s, when production had been falling for two decades.
“All the majors and all the companies with names you’ve heard left with their employees,” said Karr Ingham, an oil and gas economist. “Conventional wisdom was this place was going to dry up.”
Chevron was the only major that stayed in the Permian. It holds 2.3 million acres and owns most of its mineral rights, too, but until recently left drilling to others.
But this month, CEO Mike Wirth called the Permian its best bet for delivering profits “north of 30 percent at low oil prices.”
“There is nothing we can invest in that delivers higher rates of return,” Wirth said this month at its annual investor meeting in New York.
Matt Gallagher, CEO of Parsley Energy Inc, calls the majors’ investments “the best form of flattery” for independents operating here.
Parsley holds 192,000 Permian acres — most of which was snatched up on the cheap during oil busts — and sees its smaller size as an advantage in shale.
“We’re not finished yet,” Gallagher said. “We can move very quickly.”
The majors have greater infrastructure, but independents continue to innovate and design better wells, said Allen Gilmer, a co-founder of Drillinginfo.
“Nothing is a bigger motivator than, ‘Am I going to be alive tomorrow?’” Gilmer said.
“Hunger and fear is something that every independent oil-and-gas person knows — and that something no major oil-and-gas person has ever felt in their career.”

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6 hours ago, Mike Shellman said:

 

I quit. Whatever I say that is factual or evidential you and others will simply attack me for it. Or flood the forum with cherry picked links from the internet. That's pretty much all you guys have got. If asked to model the way out of debt, the way forward for the shale oil industry, so it can deliver what it has promised America, you couldn't do it if you had to. 

 

So now you are the victim?  LOL!

I think you really don't much understand how the economy really works.  You don't realize how much profit is plowed back into useless products that never come to fruition in these big companies like IBM, Apple, Microsoft, and a host of other tech companies.  There are many projects funded by stock issuance and debt that never work and eventually collapse.  The world continues on it's merry way writing off bad debts as it always has.  There will always be bad debts that are written off later, it doesn't mean much in the end.  Your arguments against shale are valid for a lot of other industries as well.  If you look at the debt to equity ratio of most US households you will find they are upside down.  So what?

Should we all throw our hands up and quit?  LOL!

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Has anyone read 'The Shale Boom is About to go Bust' by Nick Cunningham in todays 'Articles' on OilPrice.

An interesting perspective on the technology issues.

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