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Back to Permian: US Oil Comes Full Circle

By: staffjam Tuesday July 15, 2014 11:26 am

Much larger than Eagle Ford and once thought to have reached peak production, new technology has brought us full circle back to the Permian Basin in Texas and New Mexico, where the recent shift to horizontal well drilling has rendered this play the unconventional ground zero.

Determining where the next real oil boom will be depends largely on following the technology, and while the Permian Basin has been slower than others to switch from vertical well drilling to horizontal drilling, horizontal has now outpaced vertical, and investors are lining up to get in on the game.

Until about 12 years ago, virtually all wells in the Permian were vertical. As of last fall, however, horizontal and directional rig counts—meaning, non-vertical drilling rigs—have now begun to exceed vertical, according to RBN Energy.

But what they’re also looking for are developers who are seeing strong economics in both vertical and horizontal wells. It’s all about balance, and this co-mingling of multiple zones, with the ability to complete both horizontal and vertical wells economically is the best bet for investors.

The Permian Basin now boasts the top rig count in the US. Just this week, the number of rigs exploring for oil and natural gas in the Permian Basin increased by to 560, according to the weekly rig count report released Thursday by Houston-based oilfield services company Baker Hughes.

What’s more, according to Bernstein Research, the Permian Basin will top the charts for North American spending growth in 2014, with an amazing 21% increase. And 2013 was already a stellar year for the Permian.

Permian production last year increased by 280,000 boe/d to 2.3 million boe/d, comprised of 1.4 million b/d of oil and 5.3 bcfd of gas, according to the US Energy Information Administration.

This technology has changed the way we think about the Permian Basin, once the darling of American oil production and then lost in the shadow of Eagle Ford and Bakken. While Eagle Ford and Bakken were viewed as the “bigger plays” at the start of the unconventional boom in the US due to the fact that new technology debuted here harder and faster, the Permian is back and it’s bigger than ever.

“The Permian Basin is much larger than the Eagle Ford play, and it also contains over 20 potentially productive zones, while Eagle Ford has only one zone,” Parker Hallam, CEO of Crude Energy—a small-cap company, not publicly traded, operating in the Permian, told Oilprice.com.

Hallam particularly noted the “excellent quality rock” in the Wolfcamp, Fusselman, Cline, Mississippian and Strawn zones.

“The Wolfcamp is one of the better producers in the Permian. It can be up to 1000 feet thick and is composed of multiple individual zones, several which could be production. Wolfcamp is attracting a lot of attention right now because of the horizontal drilling through the normally tight limestone,” he said.

Hallam also noted that while horizontal drilling is changing the future of the Permian Basin, “vertical completions using new technology like fracking and co-mingling multiple zones are turning out top results and drillers are seeing strong economics in these wells.”

Leading the pack in the Permian are Devon Energy Corp., Concho Resources, Pioneer Natural Resources and Chevron, with Wolfcamp probably the key focus of development activities, and the leading formation in terms of production increases. Devon in particular is being singled out by analysts for its large acreage in the Permian, couple with its transformative turnaround that could render it one of the largest crude oil producers in the US.

The only challenge with the Permian—which is on trend to see continual increases in production—is the pipeline takeaway capacity, according to RBN Energy. “The bottom line is that crude oil production in the Permian is growing rapidly, and today there is not enough pipeline takeaway capacity to efficiently handle the volume”, but that should correct itself soon with new pipelines coming online.

Bloomberg quoted Bruce Carswell, West Texas operations manager for Iowa Pacific Holdings, as saying that the forecast through July is that volumes are going to continue to move out of the region by rail.

The Permian Basin Petroleum Index, put out by Amarillo economist Karr Ingham, which examines several industry metrics to measure the health of the oil and gas business in the region, was almost 10 percent higher in May than a year earlier.

Regardless of pipeline capacity, Permian Basin crude is shaping up to be the next big oil boom thanks to new technology. Eagle Ford and Bakken became economical only after being drilled horizontally, so with the final shift to dominate horizontal drilling in the Permian, the game has only just begun.

Source: https://oilprice.com/Energy/Crude-Oil/Back-to-Permian-U.S.-Oil-Comes-Full-Circle.html

By James Stafford of Oilprice.com

 

New Spy Technology to Spawn Oil Revolution

By: staffjam Monday March 3, 2014 3:04 pm

The future of oil exploration lies in new technology–from massive data-processing supercomputers to 4D seismic to early-phase airborne spy technology that can pinpoint prospective reservoirs.

Oil and gas is getting bigger, deeper, faster and more efficient, with new technology chipping away at “peak oil” concerns.  Hydraulic fracturing has caught mainstream attention, other high-tech developments in exploration and discovery have kept this ball rolling.

Oil majors are second only to the US Defense Department in terms of the use of supercomputing systems, which find sweet spots for drilling based on analog geology. These supercomputing systems analyze vast amounts of seismic imaging data collected by geologists using sound waves.

What’s changed most recently is the dimension: When the oil and gas industry first caught on to seismic data collection for exploration efforts, the capabilities were limited to 2-dimensional imaging. The next step was 3D, which gives a much more accurate picture of what’s down there.

The latest is the 4th dimension: Time, which allows explorers not only to determine the geological characteristics of a potential play, but also tells them how a reservoir is changing in real time.   But all this is very expensive.  And oilmen are zealous cost-cutters.

The next step in technology takes us off the ground and airborne—at a much cheaper cost—according to Jen Alic, a global intelligence and energy expert for OP Tactical.

The newest advancement in oil exploration is an early-phase aerial technology that can see what no other technology—including the latest 3D seismic imagery—can see, allowing explorers to pinpoint untapped reservoirs and unlock new profits, cheaper and faster.

“We’ve watched supercomputing and seismic improve for years.  Our research into new airborne reservoir-pinpointing technology tells us that this is the next step in improving the bottom line in terms of exploration,” Alic said.

“In particular, we see how explorers could reduce expensive 3D seismic spending because they would have a much smaller area pinpointed for potential.  Companies could save tens of millions of dollars.”

The new technology, developed by Calgary’s NXT Energy Solutions, has the ability to pinpoint prospective oil and gas reservoirs and to determine exactly what’s still there from a plane moving at 500 kilometers an hour at an altitude of 3,000 meters.

The Stress Field Detection (SFD) technology uses gravity to gather its oil and gas intelligence—it can tell different frequencies in the gravitational field deep underground.

Just like a stream is deflected by a big rock, SFD detects  gravity disturbances due to subsurface stress and density variations.   Porous rock filled with fluids has a very different density than surrounding solid rocks. Remember, gravity measurement is based on the density of materials. SFD detects subtle changes in earth’s gravitational field.

According to its developers, the SFD could save oil and gas companies up to 90% of their exploration cost by reducing the time spent searching for a reservoir and drilling into to it to determine whether there’s actually any oil and gas still there.

“Because it’s all done from the air, SFD doesn’t need on-the-ground permitting, and it covers vast acreage very quickly. It tells explorers exactly where to do their very expensive 3D seismic, greatly reducing the time and cost of getting accurate drilling information,” NXT Energy Solutions President and CEO George Liszicasz, told Oilprice.com in a recent interview.

Mexico’s state-owned oil company Pemex has already put the new technology to the test  both onshore and offshore in the Gulf of Mexico, and was  a repeat customer in 2012.  They co-authored with NXT a white paper on their initial blind-test used of the survey  technology.

At first, management targeted the technology to frontier areas where little  seismic  or well data existed.  As an example, Pacific Rubiales Energy is using SFD technology in Colombia, where the terrain, and environmental concerns, make it difficult to obtain permits and determine where best to drill.

The technology was recently  contracted in the United States for unconventional plays  as well.

Source: http://oilprice.com/Energy/Energy-General/New-Spy-Technology-to-Spawn-Oil-Revolution.html

By. James Burgess of Oilprice.com

The Boundless U.S. Natural Gas Boom: Exclusive Interview with EIA Chief

By: staffjam Sunday February 23, 2014 7:09 pm

The Energy Information Agency (EIA) has predicted that natural gas production in the US will continue to grow at an impressive pace. Right now output is close to 70 billion cubic feet a day and is expected to reach over 100 billion cubic feet per day by 2040. The trend is likely to continue without hitting a geologic “peak”, and along with this trend will come new marketing opportunities for America.

In an exclusive interview with Oilprice.com, EIA Administrator Adam Sieminski discusses:

  • What’s at stake in lifting the US crude export ban
  • Whether lifting the ban is inevitable
  • Why energy-related CO2 emissions will likely climb this year
  • What we can expect from US coal output through 2014
  • Why US natural gas production will continue to grow strongly
  • Where we can expect (unexpectedly) new production to come from
  • Why Alaska just might surprise us
  • Where the biggest new shale opportunities lie
  • How production increases might come from ‘non-shale’ formations
  • The potential for Colombian shale
  • What to expect from Mexico’s reforms
  • What the Panama Canal expansion really means
  • Why we will see new marketing opportunities for the US

Interview by James Stafford of Oilprice.com

Oilprice.com: US mainstream media are heralding the debate over lifting the US crude oil export ban as potentially one of the most critical for this year. While most agree this is not likely to happen anytime soon, is it an eventuality?

Adam Sieminski: When I first took office at the EIA, I said that light sweet crude oil production was growing very rapidly, and that it would ultimately have a number of impacts on the energy infrastructure in the US; for instance, that we would see changes in things like movement of oil by rail.  We would see changes in refinery configurations designed to deal with light sweet crude. The Gulf Coast refineries in the US over the past decade were upgraded to run heavy sour imports, and so there are issues with the ability of refineries in the US to handle rapid increases in light sweet crude oil production.

I noted at the time that at some point, policymakers were going to be confronted with all of these changes resulting from the enormous shift in thinking about US production growth.  Five or 10 years ago, everybody thought that US oil production would just go down, and demand would always go up. Now we have in the EIA’s forecast over the next five years very strong growth in crude oil production and weak growth—if not negative trends—going on in gasoline and liquid fuels demand.  This creates an interesting atmosphere.

Is lifting the crude export ban inevitable? I’m not sure that anything is inevitable. Certainly what I’ve learned in the last five years is that the inevitable declines in production and growth in demand didn’t come true.

Oilprice.com: What are the congressional hurdles faced here?

Adam Sieminski: I don’t know that there’s a hurdle. That’s a question that’s going to be dealt with by policymakers. Energy policy issues generally tend to involve environmental concerns, national security concerns, and economic concerns.

The biggest hurdle that congress faces is just having good information on future trends in supply and demand, refinery configurations and pipeline and railroad transportation infrastructure.

Oilprice.com: What would be the consequences of lifting this ban, for the industry, for refiners, for consumers?

Adam Sieminski: Well, that’s going to be part of the debate. I don’t have the answer to that, and I doubt that anybody at this point has the complete answer to that question. What is the economic impact? Does it increase jobs or not? What is the environmental impact of producing, moving and refining the crude oil? What are the national security implications? Is it better to keep the oil here, or to move it into global markets where it might have an ameliorating effect on volatility? There are a lot of questions, so I’m not going to try to pre-judge that debate.

Oilprice.com: The EIA has noted that after two years of declining production, US coal output is expected to increase in 2014, forecast to rise almost 4%,  as higher natural gas prices make coal more competitive for power generation. At the same time, there is concern about the EPA’s proposed new carbon emissions standards for power plants, which would make it impossible for new coal-fired plants to be built without the implementation of carbon capture and sequestration technology, or “clean-coal” tech. Is this a feasible strategy in your opinion?

Adam Sieminski: Well, the facts as you laid them out are certainly what the EIA is looking at.  Natural gas prices have gone up, so in 2013, we already saw some recovery in coal at electric utilities. As a consequence, energy-related carbon dioxide emissions actually climbed in 2013 and probably are going to do so again in 2014 for the reasons that you stated.

Longer term, even without changes by the Environmental Protection Agency, there’ll be coal retirements, and the amount of coal being burned in the US will eventually come below the amount of electricity being generated by natural gas. So sometime after the year 2030, we will have more electricity in the US being produced from natural gas than from coal.

Oilprice.com: What can we expect from US onshore natural gas production over the next two years;
over the next five years? And where will production increases offset declines?

Adam Sieminski: Well, the EIA has been pretty clear on this in our Annual Energy Outlook Reference case for 2014, which we published in mid-December. We reiterated what we said the previous year: natural gas production in the US is going to continue to grow very strongly. We are close to 70 billion cubic feet a day of output now. That number will be over 100 billion cubic feet a day by 2040. Shale gas will be easily 50% or more of production by 2040.

We also see increases in natural gas production from geologic formations that we don’t consider to be shale gas. We think that there might also be some production, believe it or not, from Alaska, because the economics ultimately will favor construction of an LNG facility in Alaska that would allow production from the associated gas in the North Slope of Alaska.

Just in the last five years, we’ve seen natural gas production in the US from shale go from about five billion cubic feet a day to nearly 30 billion cubic feet a day–a huge increase. A lot of that is coming from places like the Haynesville—and more recently the Marcellus in Pennsylvania and West Virginia. In our view, those production trends are going to continue without the likelihood of running into a plateau from a geologic standpoint.

Oilprice.com: How do you see future extraction, development and commercialization of oil and gas resources in the Americas playing out over the next 5-10 years?

Adam Sieminski: Well, the big new opportunities, I think–certainly in the US and Canada–lie in the development of shale resources. There are oil and gas shale resources in places like Argentina, Mexico, Columbia, and elsewhere across the Americas. Whether or not the very rapid development of shale resources in the US can be duplicated in a lot of other countries—even in the Americas—remains to be seen. Certainly there has been some interesting progress in developing shale resources in Canada and Argentina.

I’ve been hearing from many people that they’re quite hopeful there will be developments in shale in Colombia, and given the constitutional changes that have now been agreed in Mexico, that opens up an opportunity for Mexico to step into this area.

One of the things that is happening is the increase in oil production in the US and the fact that we have very sophisticated refineries with very strong technology, while relatively low natural gas prices are allowing us to run our refineries at higher utilization rates and dispose of surplus products—by exporting petroleum products like gasoline and diesel fuel—into Latin America and Canada.

In a sense, this creates a manufacturing opportunity for the US to take a raw material, process it, and sell it abroad. It also fits in pretty well with the fact that a number of countries in Latin America have had difficulty in building and upgrading their own refineries.  So it’s opened up a marketing opportunity for the United States to take advantage of.

Oilprice.com: What can we expect from Mexico’s recently adopted energy reforms and what regional effect could this have?

Adam Sieminski: Well the Mexican government and Pemex, the state oil company, are very excited about the opportunities they see for Mexico to increase its production and to take advantage of some of the new technologies that are available through cooperation with non-Mexican companies. They believe that it is going to be instrumental in reversing some of the difficulties they’ve had in oil production and natural gas production.

It certainly looks to the EIA as something that we’re going to have to watch very carefully when considering the longer-term outlook for Mexican energy production.

We actually bumped up the Mexican numbers because of the opportunities we think will be created by constitutional reform there. If the implementation of that proceeds along the lines that the Mexicans are considering, I think we’ll probably have to look at it again.

Oilprice.com: In its latest report, the EIA notes that the Americas accounted for 20% of global natural gas trade, and while 80% of that was via pipeline, the rest was traded as LNG. How do you see this proportion changing over the next 5-10 years?

Adam Sieminski: Well, I suspect that we’re going to see more of both. Our longer-term outlook shows US pipeline exports of natural gas to Mexico going up, and we also see LNG exports from the United States increasing. We’re not responsible for permitting. What we try to do is look at the economics. We run our national energy modeling system to basically say, “What would the economics do if you let them run?” And that shows we’re likely to see increases in exports of both LNG and pipeline gas.

Interestingly, the model also says that there’s plenty of production to do that and still allow demand in the US to go up considerably. We’re seeing demand increases in natural gas use by refineries; it’s a big refinery fuel. And in the industrial sector, we see significant gains in natural gas consumption occurring in areas like bulk chemicals, food processing, and elsewhere. And then the biggest increases in natural gas may come from electric utilities, which will likely be using more natural gas relative to coal to provide electricity growth in the United States.

Oilprice.com: Is the US Department of Energy moving too quickly or too slowly to approve LNG exports to non-FTA countries?

Adam Sieminski: I think that the Department of Energy’s Department of Fossil Energy, which is responsible for permits, is moving exactly the way it should under the law to make the kinds of findings necessary from a legal standpoint. I wouldn’t characterize it as too fast or too slow. I would say that from what I can see, it’s just right given the legal framework.

Oilprice.com: When could we expect the US to become a net gas exporter?

Adam Sieminski: The EIA’s forecast is that the US will become a net exporter of natural gas before the end of this decade.

We’re already a net exporter of coal. In terms of electricity, most of our trade is with Canada, and that never really seems to have been much of an issue. The US is also a net exporter of petroleum products, so we now export more gasoline and diesel fuel than we import. We import a lot of oil products, particularly into the East and West Coasts. But we are a big exporter, mostly from the Gulf Coast, with the increase in refinery utilization down there. The overall picture now is one in which the US trade deficit is being reduced by growing oil and petroleum product exports.

The only big outstanding question is: could the US potentially be a net exporter of crude oil? In the EIA’s Reference case forecast, that doesn’t seem likely. Despite the fact that our production is rising while demand is falling, we’re still importing about five million barrels a day net of of crude oil and products. It doesn’t seem likely that net importsd are going to go to zero–at least not given the facts as we currently see them. It’s possible, in a high petroleum resources case combined with a technology and policy-driven low demand case, but not probable.

One thing you want to keep in mind is what it would mean, exactly, if the US were completely self-sufficient in energy. Some people like to use the phrase, “energy independence.” We would still be part of a global trading system in energy, and particularly petroleum products and crude oil. And if oil prices go up globally, they’re going to go up in the United States. If there’s a geopolitical problem somewhere or a weather problem somewhere—anything—the US would be impacted just as it has always been. The US has a lot of interest in what’s going on around the world, in the Middle East and elsewhere, regardless of whether it is independent or self-sufficient in fuels. Those political and economic interests will remain whether we become an exporter or not.

Oilprice.com: What role will the expansion of the Panama Canal play in this?

Adam Sieminski: What they’re doing is widening the Panama Canal. They’ll make the Canal itself wider and the locks longer, and the net result will be the potential to save in transportation costs through the use of larger oil tankers and LNG tankers. This offers an opportunity to reduce the costs associated with global trade. It is something that I know Panama and all of the customers who use the Panama Canal are very interested in seeing happen. There have been some cost and labor issues, but I’m sure those will be resolved and this expansion will eventually be completed. When that happens, it’s going to reduce the cost of moving goods back and forth between the Atlantic and the Pacific, and that’s going to apply particularly to things like liquefied natural gas and oil.

Source: http://oilprice.com/Interviews/Boundless-Natural-Gas-Boundless-Opportunities-Interview-with-EIA-Chief.html

By. James Stafford of Oilprice.com

Are Canadian Energy Stocks Set for a Rebound?

By: staffjam Thursday November 21, 2013 5:42 pm

As Canadian energy stocks are finally seeing a bit of a push, and demand for Canadian commodities looks set to rise, juniors are confident that economics will ensure that Canadian oil—the cheapest in the world—will find its way to more markets, with or without Washington’s approval of Keystone XL. In the meantime, some sweet spots in the Western Canada Sedimentary Basin, like the Montney shale formation—are showing promise as gas turns into oil for the bigger players, while the juniors are hoping to piggyback on this new success.

In an exclusive interview with Colin Soares, the CEO of High North Resources we discuss:

•    How Libya and Warren Buffet boosted Canadian energy stocks
•    Why we can expect stronger demand for Canadian commodities
•    Why simple economics favors Canada’s cheap crude
•    Why Canadian juniors are banking on $70 oil
•    Why oil price volatility will haunt us
•    Why we shouldn’t expect a big change in Canadian crude price differentials just yet
•    Why Washington’s approval of Keystone XL isn’t as critical as before
•    What we can expect from all the hush-hush over the Western Canadian Sedimentary Basin
•    How the key for juniors in the Montney shale is to piggyback off the shift from gas to oil exploration

Interview by James Stafford of Oilprice.com

James Stafford: For the first time in months, Canadian ETFs are seeing an increase in flows—especially for financial and energy stocks. What is pushing this?

Colin Soares: I think there were a few factors. International money started flowing back into Canadian energy as global oil prices jumped 15%, on the back of Libya production falling down.  WTI followed suit and all of a sudden the Canadian oil price was over $100 a barrel.  Cash flow and profitability soared in Q3 2013.

Canadian management teams have got so used to deep oil price discounts, we focus only on developing top assets—ones that payout in a year on $75 oil.  That’s certainly true for the juniors—and there are hundreds of them in Canada.  We have become a lot more disciplined in the last year as investors switched from growth at all costs to sustainable growth; growing within cash flow.

Then I think you just combine all that with the fact that the valuations on Canadian oils were so cheap—from juniors like us right through to seniors like Suncor. Warren Buffett bought a big chunk of Suncor this year and I think that helped money flows into our sector as well.

James Stafford: Can we expect stronger demand for Canadian commodities?

Colin Soares: Absolutely. The Americans are not allowed to export their crude, and Canada is. We now have the cheapest oil in the world, and simple economics says it will find a way to a market. The light oil might go to the west coast via a new pipeline, or it might travel across Canada to the eastern Maritime provinces, but it will find a way—for both heavy and light oil.

The US will always want our heavy oil, as their refining complex is mostly heavy oil. And our heavy oil trades at a discount to both Mexican and Venezuelan heavy oil.

James Stafford: What does this mean for Canadian juniors?

Colin Soares: It means we can budget on at least $70 oil, which is what we’re doing.

James Stafford: Canadian heavy crude is sold at a large discount to US and world crude, but analysts are now predicting the end of these big price “differentials” as they’re called, for Canadian heavy oil. Do you see an end to this volatility, and what factors will contribute to closing this gap?

Colin Soares: No, volatility will absolutely stay. Just having one refinery go down creates a big differential for a few days. And of course, pricing is seasonal as refinery maintenance happens in spring and fall, and oil prices are lower then, and the differentials are bigger then. You just get used to that and budget an overall price. Strong projects, with good economics will make money regardless of fluctuations in the oil price.

At High North we have been using a $70/barrel oil price to calculate our numbers and we are confident that we still have one of the fastest payouts of any wells in North America.

James Stafford: How do you see this playing out by the end of the year and into the first quarter of 2014?

Colin Soares: Differentials will stay larger than normal—though what’s normal anymore?—through Q1 2014 until more pipeline capacity gets into place around North America.  There is 800,000 barrels a day of refining capacity coming online in just the next two weeks!  That is more competition and will raise North American oil prices.

And pipelines are racing to keep up to production increases and doing a good job.  TransCanada’s Keystone South project will be starting in just a few weeks taking oil from Cushing down to Houston.

James Stafford: How much depends on Washington’s approval of the northern leg, the Keystone XL pipeline?

Colin Soares: Fundamentally, not as much as before—because of huge increases in crude being transported by rail—but from a market point of view I think it’s still a big deal– I  think market valuations would increase with Keystone approval.
But even with the approval of the Keystone XL, we are still a long way off until the pipeline is built and price differentials narrow to be really tight. Once again, good projects with strong economics will make money regardless of the fluctuations in the oil price.

James Stafford: Will Canada continue to increasingly rely on rail transport for oil products despite the Quebec train disaster?

Colin Soares: Yes, and in the US as well.  Right now Canada is transporting about 200,000 bopd of oil by rail, and experts are thinking that will more than double in two years. Until new pipelines are approved and built, oil products will rely more on rail.

James Stafford: As we head into a New Year, what will be the key drivers for the Canadian oil and gas industry?

Colin Soares: I think the market will be more focused on balance sheet and financials, not just straight growth, or growth at any price.  It’s a lot more about sustainability now.  With a lower oil price, you will have to show you can grow inside cash flow, or very close to cash flow.  Plays where the wells payout their costs really quickly—like around a year–will get a premium.   And that’s the type of asset we have.

James Stafford: Canada’s National Energy Board just said the Montney Formation in the
Western Canadian Sedimentary Basin is one of the largest gas deposits in the world—some 450 trillion cubic feet of gas, 14.5 billion barrels of liquids and 1.1 billion barrels of oil.  What does that mean for the Canadian energy industry?

Colin Soares: For gas, it means we have decades of supply—and low cost supply.  All those liquids like propane and condensate pay for the gas wells—so the gas has almost no cost to it.  The liquids make the gas very economic.

And so when everybody starts drilling these big gas wells, they’ve been finding oil as well.  And you’re seeing  a lot more exploration now targeting light oil to the North.  The oil is shallower, and so it’s cheaper to get it out of the ground—it’s actually a perfect play for a junior like High North.

James Stafford: How much can we expect to be spent on developing the Montney oil play for this year and next?

Colin Soares: There are several companies working in north-western Alberta who are having success developing the Montney oil play. Long Run Exploration recently announced a $110-million expenditure to develop its Montney oil project—they’re right beside us developing a big fairway. RMP Energy recently raised $50 million through GMP Securities, bringing their capital budget to $168 million for their Montney project.

James Stafford: What’s the sweet spot in the Montney formation for oil?

Colin Soares: That’s too early to say yet.  I would love to say we are in the sweet spot, being as Long Run is just to the north and east of us and RMP is just to the south and west, but the reality is that RMP right now looks like it has an initial sweet spot at Ante Creek.

But there is still a learning curve involved with drilling successful wells. The key for the juniors is to piggyback off the knowledge of larger players like Long Run and RMP.

James Stafford: Colin, thanks for taking the time to join us today.

Source: http://oilprice.com/Interviews/Are-Canadian-Energy-Stocks-Set-for-a-Rebound-Interview-with-Colin-Soares.html

The Big Winners in Kenya’s Oil Debut

By: staffjam Wednesday October 23, 2013 11:09 am

Kenya will start pumping its first commercial oil next year and begin exporting in 2016, but this is just the opening salvo: new discoveries in recent months and fast-track new well development make Kenya the darling of East Africa from an investor’s perspective.

Kenya is set to soar past Uganda, which discovered oil much earlier, but is now having a hard time getting it out of the ground and into the market. And the next five months should bring not only news of the first commercial output for Kenya, but new commercial prospects coming online.

As the discoveries pile up for pioneers British Tullow (TLW-LSE) and Canadian Africa Oil (AOI-TSXv), the plan now is to escalate development and further the pace of exploration, while a third winner in this scenario—Taipan Resources (TPN-TSX)—is set to benefit enormously by owning acreage right next to the pioneers’ high-reward prospects.

Tullow, in partnership with Africa Oil–made the first discovery in western Kenya just last year, and in total have discovered more than 300 million barrels of oil equivalent resources in Kenya’s South Lokichar Basin, and they are still exploring.

In late September, the duo announced a fourth crude-rich discovery at Ekales, hitting a net oil pay of 60-100 meters. Significantly, this discovery is right between the Ngamia-1 and Twiga South-1 wells that first put Kenya on the oil map, and the reservoir properties are similar.  Drilling success here has been 100% and this is the fourth consecutive wildcat discovery in this basin since March 2012.

In the next 12 months we can expect another 12 wells to be drilled along Kenya’s “string of pearls”, and what investors are sure to be eyeing is the fast progress on two new wells–Bahasi and Sala–being drilled by Tullow and Africa Oil. These wells—targeting 700 million barrels between just the two of them—are in eastern Kenya, and this is where Taipan is.

The catalysts here for Taipan are increasing by the day.

The Bahasi is a 300-million-barrel well that was spudded earlier this month and should be completed around December this year. Upon completion of Bahasi, Tullow and Africa Oil will start drilling the Sala well, which is a massive 402-million-barrel prospect.

This spreads the discovery net wider, and Taipan is eagerly eyeing the results because both new wells are right next to their own Block 9 acreage, so a hit for one here means a hit for all.  They’re all targeting the same geology—the Tertiary part of the Lower Cretaceous.

Africa Oil and operator New African Global Energy also expect to spud the highly prospective El Kuran well this month. El Kuran is just to the north of and on trend with Taipan’s Block 1. It’s a low-risk prospect because there has already been a discovery and it’s really about testing commerciality and flow rate.

And with the 100% success rate for drilling in Northern Kenya so far, there is reason to be optimistic.

For Taipan, there are plenty of other catalysts as well, including a farm-out agreement earlier this month for 55% of its Block 2B with Premier Oil Investments Limited, which will cover the cost of drilling and testing its Pearl-1 prospect. The drilling campaign should be in place by the second quarter of next year.  A lot of information on geology will come to light—before Taipan drills–from the Bahasi and Sala wells.

It was only in 2012 that Tullow and Africa Oil struck the first oil in Kenya. This makes a commercial production timetable of 2014 and export goal of 2016 an amazing success story and puts Kenya leaps and bounds ahead of its neighbors.  With a string of successes and money pouring into the country from major oil companies—over $100 million in deals have recently been announced—Kenya’s risk/reward ratio is tipping heavily into investor’s pockets.

By. James Stafford

Originally published at Oilprice.com

No More Spills? New Technology Could Transform the Pipeline Sector

By: staffjam Monday August 12, 2013 8:57 am

The 2010 Kalamazoo spill and the 2013 Exxon leak in Arkansas are the most glaring incidents, but these are just the big leaks that are found right away and reported.

Most leaks are found eventually—but there is money to be saved and damage to be avoided by catching them at the smallest rupture. Right now, we rely on pigs in the pipeline to do this.

It’s called “pigging”. Pigs are inspection gauges that can perform various maintenance operations on a pipeline—from inspection to cleaning—without stopping the pipeline flow. The first “pigs” were used strictly for cleaning and they got their name from the squealing noise they emitted while travelling through the pipeline. The current generation of “smart pigs” can detect corrosion in the pipeline and are thus relied on for leak detection.

The Kalamazoo and Arkansas leaks were massive and caused by complete pipeline ruptures. These are rare incidents that account for less than 10% of leaks. But the small leaks–those that traditional pipeline detection systems don’t catch—account for more than 90% of US pipeline leaks.

According to a recent report from the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA), the majority of leaks are smaller but can persist for months or even years, and those that are even reported are generally done so by people who have stumbled upon them by accident.

The fact remains that current systems and technologies only detect 50% of leaks. We need new solutions if we want to avoid another Arkansas, or another Kalamazoo.

The “pigs” are the darlings of the regulators, who force operators who have had any problems to “pig” their lines at a massive cost of over $1,000 per kilometer.

Certainly, today’s smart pigs are well advanced beyond their ancestors—the balls of rags wrapped with barbwire, but they have their shortcomings.

Pigs can spot general corrosion and identify potential areas of concern, but they cannot detect pinholes in pipelines as their spatial resolution is poor and they can only see corrosion that is 1-2 inches in size. This is significant because a small leak of 10 barrels per day from a liquid pipeline operated at a standard pressure would come from a hole much smaller than this.

They are also only deployable over tens of kilometers, not the thousands needed.

Even if all the pipelines in the world were “pigged” every year, a pipeline operator would still not be able to ensure that small leaks are being detected.

For the larger pipes, the industry relies on SCADA. SCADA is a basic infrastructure monitoring system, where remote hubs relay data back to central monitoring point, using fiber-optic cable or other communications equipment. But it is not enough on its own.

A case in point is this: A SCADA system was working normally on the Pegasus pipeline in Arkansas at the time of the rupture and helped Exxon verify that an accident had occurred. Pegasus did not, however, have a Computational Pipeline Monitoring (CPM) program in place on the pipe. It wasn’t enough. Indeed, in late 2012, PHMSA issued a 17-page warning to Exxon about its insufficient pipeline leak detection.

Then we have Keystone XL, which is always in the spotlight, most recently when TransCanada said it would opt out of new pipeline leak detection systems and stick with traditional methods that many believe are not good enough.

The 90%+ of leaks are small and more of a concern for the miles and miles of aging pipelines that crisscross the US, while new pipelines, like Keystone XL will benefit from new technologies during their construction, such as better pipe metallurgy and better welding. This will mean less chance of leaks, but not a zero chance. The fact is that the leak detection systems that will be used by new pipelines like Keystone XL (assuming it gets the green light), are not really any better than the current fare.

There is new technology floating around out there—but it’s new and relatively untested in the marketplace.

RealSens remote-sensing pipeline detection technology aims to pick up where SCADA and the pigs leave off, detecting leaks over an entire pipeline network.

According to Banica, Synodon’s CEO, realSens can actually save companies money by detecting the leaks sooner and faster and thus reducing the amount of spilled product and the environmental damage. But it’s a new technology that was only introduced into the market 12 months ago.

Still, some of the big operators remain skeptical of new pipeline leak detection systems, as their cost-saving applications are as yet unproven.

“The first hurdle is that operators might not be aware that it exists and what the capabilities are. The second hurdle is that they have a hard time believing it works and have to see proof through customer field tests, which are currently ongoing,” Banica told Oilprice.com.

But the issue of pipeline leak detection will increasingly be on everyone’s radar following the Quebec train disaster that killed at least 38 people, and counting. No pipeline failure has ever come close to this level of human carnage. This will help shape the transport debate.

What the Quebec tragedy demonstrates, says Banica, is that pipelines are a far better option than rail. “Whereas pipelines do not kill as many people as rail (or even truck transport, as more drivers die due to accidents), they do pose a bigger environmental risk than rail due to larger potential leaks and releases.”

Source: http://oilprice.com/Energy/Energy-General/No-More-Spills-New-Technology-Could-Transform-the-Pipeline-Sector.html

By. James Burgess of Oilprice.com

When Drilling Is Expensive, Piggyback: Interview with AOS

By: staffjam Monday July 29, 2013 11:44 am

Africa is becoming the top choice for North American oil companies looking to diversify, and the East African Rift is the hottest of the hot, with Kenya waiting on commercial viability, Angola and Ghana already on the road to rival Nigeria and two newcomers—Namibia and Zambia—where the doors have been thrown open for exploration. Getting in on Namibia and Zambia is an extremely expensive endeavour, but here’s a way to de-risk this adventure, keep your shareholders calm and strategically position yourself to take advantage of the next big find without footing the massive drilling bill: Buy up a ton of acreage and sit back and let others do the expensive exploration and drilling on territory adjacent to yours. Then strike and watch offers come in.

In an interview with Oilprice.com, Alberta Oil Sands (AOS) CEO, Binh Vu … discusses:

•          How to get in elephant-sized plays in the East African Rift

•          How to save cash by piggy-backing on others’ expensive exploration

•          Why Namibia could be a major oil monster

•          What makes Zambia such an attractive oil venue

•          Other African plays that are worth looking into

•          Why it’s hard for juniors to compete in Africa

•          Why someone will always need Canadian oil sands

•          What heavy oil economics will look like over the coming years

•          Why Canada’s Algar Lake is a major sleeper play

•          What qualities investors should look for when betting on juniors

Interview by James Stafford of Oilprice.com

James Stafford: With the oil discoveries in Kenya and a lot of optimism over other rifts and lake systems including those present in Uganda, Zambia, Tanzania, etc. the East African Rift System has become an emerging oil hot spot. What we want to know is how to make money here without spending a ton of cash in exploration and drilling? What’s the smart way to stake a claim on the East African Rift Basin?

AOS: That is a great question. The truth is that this area has become quite expensive as it has been found to be increasingly prolific. Major signing bonuses, deposits, and commitments are required in spots like Kenya, Tanzania, and Uganda. There is very little opportunity for the junior explorers to compete.

We believe that Zambia is a fabulous jurisdiction because it shares the geology and rock age in certain large areas that have hosted the Lake Albert Discovery and the Block 10BB Kenya discovery. However, it is totally underexplored for hydrocarbons and thus provides much cheaper access to very prospective areas. Our company has successfully tied up ~18 million acres or what we believe covers about 33% of the attractive rift areas in Zambia – which equates to oil and gas rights over about 8% of the country.

James Stafford: How does an exploration company on a budget go about covering and “high-grading” targets over such a large area?

AOS: Without a doubt that is a highly important question for any company engaged in the pursuit of elephant-sized targets in new frontiers. One of the things that we do is first is aim for concession agreements that don’t tie us to expensive immediate seismic commitments. Second we eschew large and expensive 2-D seismic programs in favor of a process of high grading using satellites, other remote sensing techniques, and ‘ground truthing’.

We estimate that by using satellite data analysis over a number of criteria–gravity gradiometry, thermal emissivity analysis, geobotany analysis including vegetation anomalies and geo-microbial review over specific high-graded areas on our acreage–we can save millions of dollars and years of time. We then get to specific areas that are ready for smaller, focused electroseismic surveys / 3-D surveys, and that can then be attacked as drillable targets either to take on ourselves, or to farm down to majors who are looking for the next major rift discovery.

James Stafford: What does the playing field look like right now in Zambia? Who’s there, what are they doing, and how are you positioned to take advantage of all the money being spent there on exploration and drilling?

AOS: There are a number of companies there and we have focused on two lakes as well as two dry rifts that show very promising gravity responses from the most up to date databases. Our number one focus is on Lake Tanganyika. This lake spans through Burundi, Tanzania, DRC, and Zambia.

There are currently to our knowledge at least three major active seismic programs on Lake Tanganyika including one recently completed by Beach Energy, an Australian company with a $1.75 billion valuation. Beach is directly adjacent to AOS, on the Tanzania side of the Lake. It is likely that Lake Tanganyika will see at least 1 drill hole in 2014.

We like Lake Tanganyika as the right spot for the next Lake Albert (3.5 billion barrels reserves) discovery because of the almost identical geological setting and rock age as well as the size of the Lake and the major indications of an existing petroleum system. Lake Tanganyika has multiple oil slicks and natural oil seeps including one that is believed to be the largest natural oil seep in the world. You can see it from Google Earth.

James Stafford: You’ve also recently acquired acreage in Namibia, which just made its first-ever commercial oil discovery. What are the prospects here and what kind of timeframe are we looking at?

AOS: I’m glad that you asked that. Namibia to us is a potentially direct analogue to all of the major offshore discoveries in Brazil (plate tectonics theory) and Angola to the north. Offshore Namibia has the identical age and rock type as the discoveries in offshore Angola. Combined, those two countries have nearly 30 billion barrels in reserves.

Namibia itself, however, remains highly underexplored with only 16 wells drilled in 20 years–seven on Kudu Gas Field alone–and the majority of the rest were shallow shelf wells. People are starting to get the idea and now. BP, Petrobras, Repsol, Galp Energia, HRT, are all there.

HRT has had success there on their first well of this three-well campaign where they discovered light oil for the first time. Their second well was dry. The third well on which they will begin drilling in August in their PEL-24 block which borders directly on to AOS’ 2.5 million acre land package in the Orange Basin – blocks 2712A and 2812A. We are at ground zero.

HRT rates their play chance there at 25% and to my knowledge it is their biggest target–a 30 billion barrel monster. If that one works, I would think that there will be companies knocking down our door. We will know likely in late September, maybe the beginning of October.

Regardless, there should be at least five more wells drilled and $500 million to $1 billion being spent offshore Namibia over the next 12-18 months, so it really fits well with our strategy of being in highly active basins where majors and big independents are spending lots of money around us to prove up major discoveries.

James Stafford: AOS’ new Africa portfolio is an ambitious diversification of its original assets in Alberta oil sands. Why the need for diversification here?

AOS: It is indeed; however, I think that what shareholders need to understand (and many of ours do not) is that AOS has been traded for the last 24 months strictly on its balance sheet. It basically always trades at its cash per share. Why is that? Very simply there is or has been in recent times, very little capital market appetite or excitement for small companies developing SAGD oilsands plays.

Athabasca Oil was one bright spot, but that was a marvel of financial engineering that caught a window.

AOS has 500+ million barrels of oil sands resources which are getting no value. Combine a terrible junior market with complete apathy for this asset class, and the result is a share price that declines almost in lockstep with the treasury, and a total lack of response or enthusiasm to basically just about any kind of positive news.

We feel that while AOS is underpinned by its cash and by real assets on which the company has spent almost $65 million developing since 2007, it adds meaningfully to shareholder value by bringing into the fold, as cheaply as possible, blue sky scenarios with major lottery ticket potential and requiring little to no cost commitments over the next 12-18 months.

Ultimately, as we gain approval at our flagship Clearwater project in Alberta, part of our plan as we examine our options to unlock value in two distinct plays could be to dividend out our African assets to shareholders into a new company on a 1 for 1 basis, such that shareholders retain 1 pure play share of Oilsands in Alberta (Clearwater, Grand Rapids, Algar Lake), and one pure play share of our 21 million acre and growing high-impact African exploration portfolio (Zambia, Namibia, DRC).

James Stafford: Mainstream media reports generally put a price tag of $75 to produce a barrel of Canadian oil sands, but is this really reflective of the true price once you get past the start-up phase?

AOS: Some of the junior oilsands development companies that have made the transition to SAGD have stumbled without a doubt. Connacher and Southern Pacific being two recent examples. I believe, however, that the economics are actually superlative once all problems are solved, and of course you can go on producing for a very, very long time. The margins of an operation in full-swing and after start-up/growing pains, are much better than the mainstream media is reporting.

James Stafford: For how long will the US continue to need crude from Canada’s oil sands given current levels of production from US shale plays? What is the production price comparison here? Will it cost more to sustain production from wells in the Bakken and Permian Basins?

AOS: This is an interesting question. My personal view is that whether it be the US or someone else, there will be no shortage of demand for what the Canadian oil sands can produce. Further, there is a lot more certainty in terms of consistency and longevity of the oil sands assets and their production profile, once they get going.

James Stafford: What are your predictions for North American heavy oil economics over the next 2-3 years? Plenty of investors think this is the place to be with a lot of refineries coming out of turnaround and getting heavier and heavier despite all the light shale oil. Will demand for heavy oil rise?

AOS: I read analyst prognostications on this stuff every day. They can certainly have different complexions depending on who you are listening to. To me it’s pretty simple: I don’t believe that prices are going to go outside of a range (below, or above) where extremely healthy margins can be made by good operators, for their shareholders. We will be range-bound here at healthy levels is my overriding feeling on this.

James Stafford: What can we expect from AOS in terms of Canadian oil sands development in the next 6-9 months; in the next 2-3 years? What drilling will occur across AOS’ oilsands acreage?

AOS: Alberta Oilsands has four main projects domestically, and two of them are sleepers. For our flagship Clearwater asset with 373 million barrels of resources we hope to receive ERCB permits for production in Q4 of this year at an initial rate of up to 5,000 bopd, with a phase II of up to 40,000 bopd. This will be a game changer for us, and is the one thing that probably will move our market much higher immediately.

Our Grand Rapids project has resources of 119 million barrels and we have just completed an EUR study that demonstrates its ability to produce as much as 30,000 barrels a day, for 40 years. This is highly encouraging and is totally overlooked by the market.

Our third asset is a sleeper asset, in my opinion. AOS has taken on a partner to drill its Algar Lake project. We chose this partner because of its history of great exploration success. The team has, from scratch, made two separate billion+ barrel discoveries in Alberta and Saskatchewan and sold each to the majors. They want to turn their focus to Algar Lake now because it has the potential for cold flow production.  Cold flow CAPEX is ~25% of SAGD CAPEX. On the OPEX side and on the operational complications side, it is basically the same story as well. Those are fundamental and major benefits.

If I can find a couple hundred million barrels of cold flow today, I think that the world is at my door.  The 5 well program this winter will be enough to tell us if we have the next Pelican Lake – CNRL’s most profitable operating division per barrel, full stop.

James Stafford: It is no doubt a very difficult time right now for most junior oil and gas explorers and developers–whether with a domestic focus, or an international focus. What do you tell investors?

AOS: I would say that I don’t see that risk capital coming back for some time. It will be very opportunity specific and success driven. You want to look for companies that have the ability to survive for a while with the cash in the bank, are underpinned by real assets with a real value, and also can provide the excitement and possibility of a geometric return on investment.

James Stafford: And does AOS qualify for those criteria?

AOS: Not to toot our own horn here James, but my view of the world is: AOS is trading at just above cash value. Our combined PV10 between Clearwater and Grand Rapids is $823 million–or about 225X our market cap net of cash. We have a very small burn rate. We have multiple catalysts that can take us much higher in the next few months, including: Success in Namibia by HRT in September; approval at Clearwater for production in Q4; partners on our vast African acreage, or other discoveries near our rift acreage; demonstration of cold-flowing reservoirs at Algar Lake; and a strategic partner for Clearwater or Grand Rapids.

If any of these things come to fruition I think that the market and our own shareholders will sit up and take notice again and realize that right now they get all of those potential outcomes for free while we sit trading at cash value, with 500 million barrels of oil booked, and 21 million acres of prime exploration ground with 100s of millions of dollars being spent right around it.

James Stafford: Thanks very much for sharing your views with us on both the African landscape for exploration and discovery, as well as the outlook for heavy oil prices and oil sands development in Canada.

Source: http://oilprice.com/Interviews/Piggybacking-on-the-Hunt-For-Massive-Oil-Discoveries-Interview-with-AOS.html

Will Saudi Arabia Allow the U.S. Oil Boom?

By: staffjam Wednesday June 5, 2013 11:04 am

Technology, technology, and more technology—this is what has driven the American oil and gas boom starting in the Bakken and now being played out in the Gulf of Mexico revival, and new advances are coming online constantly. It’s enough to rival the Saudis, if the Kingdom allows it to happen. Along with this boom come both promise and fear and a fast-paced regulatory environment that still needs to find the proper balance.

In an exclusive interview with Oilprice.com, Chris Faulkner, CEO of Breitling Energy Companies—a key player in Bakken with a penchant for leading the new technology charge—discusses:

•    How Bakken has turned the US into an economic powerhouse
•    What the next milestone is for Three Forks
•    What Wall Street thinks of the key Bakken companies
•    Where the next Bakken could be
•    What to expect from the next Gulf of Mexico lease auction
•    What the intriguing new 4D seismic possibilities will unleash
•    What the linchpin new technology is for explorers
•    How the US can compete with Saudi Arabia
•    Why fossil fuel subsidies aren’t subsidies
•    How natural gas is the bridge to US energy independence
•    Why fossil fuels shouldn’t foot the bill for renewable energy
•    Why Keystone XL is important
•    Why the US WILL become a net natural gas exporter

Interview by. James Stafford of Oilprice.com

James Stafford: How important are Bakken and Three Forks to US energy in the big picture?

Chris Faulkner: The Bakken Shale has been the biggest driver in America’s reversal of decades of decline in oil production. It has transformed North Dakota into an economic powerhouse with the nation’s lowest unemployment rate and fastest-growing GDP—and an oil production level surpassing that of some OPEC nations. An added increment of almost 800,000 barrels per day of oil output, built in less than a decade, has helped the US reduce its dependency on oil imports from often hostile countries by 22% since peaking in the mid-2000s.

US oil production is at its highest level since 1992, and in another 5 years, it is projected to reach its highest level since 1972. More importantly, the US oil production surge will help tamp down the possibility of chronically recurring oil supply shortages and help keep a lid on oil price spikes for the foreseeable future. Additionally, the Bakken surge is helping to narrow the spread between WTI and Brent, providing even more economic incentive to develop the costly unconventional resource plays.

James Stafford: The US government recently more than doubled its estimates for Bakken and Three Forks to 7.4 billion barrels of undiscovered and technically recoverable oil and 6.7 trillion cubic feet of natural gas. How is the industry responding to this? How are investors responding?

Chris Faulkner: Some operators had already been developing the Three Forks formation ahead of the USGS revised estimate for the Greater Bakken play. That drilling in fact provided much of the knowledge about the Three Forks that led to the USGS upgrade. We’re already seeing stepped-up drilling in the Three Forks, and some of that will entail dual horizontal laterals, a real milestone that could yield spectacular IP rates. Accordingly, Wall Street analysts are upgrading their guidance on companies such as Continental Resources that are leading the Bakken charge.

James Stafford: What’s the next Bakken?

Chris Faulkner: That’s a tough one. In a sense, we’ve already seen it with the Three Forks reappraisal. But it would be exceedingly difficult to replicate the Bakken, with its vast areal extent and thick pays. Progress is being made with a modest level of drilling in the Tuscaloosa Marine Shale of southern Louisiana and Smackover Brown Dense Shale in southern Arkansas/northern Louisiana, but results have been somewhat spotty to date. Perhaps the best prospective candidate is the Cline Shale in the Texas Permian Basin. This shale covers a vast area, has very thick pay zones, and there is established infrastructure. Some estimates have put its technically recoverable resources at 30 billion barrels of oil. But it’s very early days in that play. Devon Energy is moving aggressively there, and we should get some hints of its true potential before too long.

James Stafford: How excited should investors be about the Monterrey Shale?

Chris Faulkner: Some restraint is in order. While preliminary estimates put potential Monterey Shale technically recoverable resources at more than 15 billion barrels, it’s hardly a slam dunk. There has been a flurry of leasing and some drilling to date, but as of yet no operator has “cracked the code” for the Monterey. Even apart from the substantial technical challenges and complicated geology and petrophysics, a bigger hurdle would be the widespread and entrenched anti-oil development attitudes industry faces in California, which already has the most stringent regulatory regime in the nation. Furthermore, that anti-oil stance will just gain momentum with the anti-frac campaign that the environmental pressure groups are pushing now.

James Stafford: The US government’s next auction of Gulf of Mexico acreage is expecting a bigger turnout than previous auctions. How is the bidding environment shaping up ahead of this sale?

Chris Faulkner: Excellent. Even with the near tripling of minimum bid requirements in deepwater areas, I expect brisk bidding. Operators are fine-tuning their exploration strategies in the deepwater areas, and some recent significant discoveries, such as ConocoPhillips’s huge Shenandoah find, will only stoke that enthusiasm. I think we’re also seeing the beginnings of a revival in shallow Gulf waters, judging from the high number of bids there in the last sale. Expectations of a gas price rebound were underpinned by the latest approval of another LNG export terminal—both positive for shallow-water drilling.

James Stafford: How important are Brazil’s pre-salt finds to a revival in the US Gulf of Mexico?

Chris Faulkner: The Gulf revival is proceeding quite nicely as it is with the string of big discoveries in the Inbound Lower Tertiary. However, the knowledge and best practices being accumulated in the pre-salt play off Brazil probably benefits the pre-salt plays emerging off West Africa more so than in the US Gulf, where success has been concentrated more in the subsalt. In fact, the advances gained in probing the Gulf subsalt—particular in seismic technology—laid much of the groundwork for decoding Brazil’s pre-salt. I think you’ll see the Gulf operators focus more on the Lower Tertiary as the flavor of the day.

James Stafford: How are drilling advancements contributing to a re-evaluation of old data and the collection of new data?

Chris Faulkner: There’s no doubt that MWD and LWD [Measurements-while-Drilling/Logging-while-Drilling] have helped operators gain a better perspective on old well logs. As accumulation of drilling data in real time makes even more technical advances, progress will continue. This may be the biggest contributing factor for the dramatic reductions in spud-to-release times that we’ve seen in the major unconventional plays.

James Stafford: What are the most recent major advancements in seismic imaging and data processing that are changing the way companies decide where to explore and where to drill next?

Chris Faulkner: 3D seismic is firmly established as a valuable exploration tool, especially for delineating reservoirs that have already been identified, and there are intriguing new possibilities for 4D seismic (essentially 3D seismic phases over time), especially for enhanced oil recovery and carbon sequestration applications. But in terms of pure exploration, the linchpin technology has been reverse time migration, which really got the ball rolling for subsalt and pre-salt plays in the Gulf and off Brazil and West Africa. Then explorers started using pre-stack depth migration to ultimately arrive at a fully defined 3D salt geometry, which has fueled much of the success in the Gulf.

James Stafford: What can we expect both from drilling technology and supercomputer data collection and processing over the next 5-10 years?

Chris Faulkner: We’ll probably see a growing convergence of microseismic data gathering and processing in real time and real-time drilling data gathering to enhance mapping of natural fractures in tight reservoirs that may help drillers better steer the well so as to optimize subsequent placement of frac stages.

James Stafford: Can the US really compete with Saudi Arabia in terms of production?

Chris Faulkner: Sure, just as long as the Saudis will allow it. Don’t forget the Kingdom is still the world’s swing supplier, a role it’s held since the late 1970s. It’s important to remember that the Saudis not only have the largest proved reserves of oil, it’s also the largest repository—by far—of low-cost oil reserves. Much of Canada’s oil sands and US tight oil requires $75 per barrel or more to be economically viable. Saudi Arabia also needs $75 per barrel, but that’s to support its current domestic budget. The Kingdom’s lifting costs are somewhere around $5 at last report. So Saudi Arabia could easily flood the market, as it did in the early ‘80s, if it lost too much market share, dropping oil prices to $50 or less, and US drilling and production would collapse. Ideally, growing demand from China and other Asian markets will help sustain Saudi production levels and oil prices even as the Americas become self-sufficient in oil.

James Stafford: Can we expect to see a gradual end to fossil fuel subsidies in the near or medium-term?

Chris Faulkner: Depends on what you mean by subsidy. Anti-oil factions erroneously claim that the standard tax incentives that the US oil and gas industry shares with most other American businesses are subsidies. But while these incentives are the target of some heated rhetoric, there are enough red-state Democrats in Congress to prevent them from being stripped away, especially for the independent oil companies that rely most heavily on them. A more likely development in the US would be incremental attempts to impose a “back door” carbon tax by proxy–essentially the Obama administration resorting to regulatory overreach to add to the costs of fossil fuel development, production, and consumption. This kind of disincentive essentially creates a subsidy-in-reverse.

James Stafford: Who benefits most from these subsidies and how?

Chris Faulkner: Again, if you mean standard industry tax breaks such as expensing of intangible drilling costs, expanded amortization for G&G costs, repealing the percentage depletion allowance benefit, pure-play E&P independents rely on them more heavily than integrated firms such as the majors or hybrid midstream/upstream firms. I’ve seen estimates that eliminating these incentives could slash as much as 15–20% of US drilling. But if you mean true subsidies such as those in Iran or Venezuela aimed at keeping gasoline and other fuel costs to consumers below their real costs, then the primary beneficiaries are the autocrats and dictators who might get ousted without them.

James Stafford: Is natural gas a feasible bridge to the US’ renewable energy future, and will the Obama administration’s plan to fund clean energy projects with oil and gas revenues work?

Chris Faulkner: Absolutely yes and absolutely no, respectively. The fact that US greenhouse emissions have fallen in recent years owing mainly to power plants switching from coal to low-cost natural gas illustrates the first point quite clearly. The fact that US LNG export projects are moving ahead underscores the point that there are abundant gas resources to support that bridge.

As to the second point, one word: Solyndra. How do you think Americans will react to their energy bills spiking so that more of their tax dollars can be flung down that rat hole? How reticent do you think the Republicans will be about pointing that out?

James Stafford: How important is Keystone XL to the US’ energy future?

Chris Faulkner: Keystone XL is important for several reasons. First, blocking the project will alienate our most important energy trading partner, Canada. Some folks talk about US energy self-sufficiency, but for oil that is a much taller hurdle; however, North American oil self-sufficiency could be achieved in less than a decade. Who knows how Canada will react to such a snub and an apparent violation of NAFTA? Retaliatory measures in energy trade are not out of the realm of possibility. The irony is that Canadian oil sands syncrude, bitumen, and heavy oil will continue to move south irrespective of Keystone XL’s fate, so any purported environmental benefits from stopping the project are a wash. And Gulf Coast refiners are eager to replace declining supplies of heavy crude from Mexico and Venezuela (not to mention the reliability of the latter’s supplies) with low-gravity feedstock from a friendly North American supplier whose supply will only increase.

Perhaps the most important impact of blocking Keystone XL is symbolic. If the administration caves to the environmental pressure lobby, it sends an unmistakable message to both sides; the result will be a perception of significantly heightened investment risk in the US oil sector and an emboldened opposition that will use the momentum of this “victory” (certainly a pyrrhic one for America) to step up opposition to oil and gas development everywhere in North America. Don’t forget: A hostile administration beset by a sluggish economy imposed the windfall profits tax that resulted in the migration of hundreds of billions of dollars of US oil and gas company E&P capex overseas; this was the single biggest factor in the US oil production decline of the past several decades. A regulatory stranglehold can have the same effect.

James Stafford: What can we expect in the next 1-2 years in terms of advanced fracking technology that could help remove some of the opposition to the process?
Chris Faulkner: The use of benign frac fluid constituents taken from food sources is certainly a significant advance and at least shows industry is trying to address the public’s concerns. Breitling Oil and Gas’ EnviroFrac™ program was founded in February 2010 to evaluate the types of additives typically used in the process of hydraulic fracturing to determine their environmental friendliness. After evaluations are completed, EnviroFrac™ calls for the elimination of any additive not critical to the successful completion of the well and determines if greener alternatives are available for all essential additives. EnviroFrac™ is a decisive move toward an even greener fluid system. By reviewing all of the ingredients used in each frac, the program identifies chemicals that can be removed and tests alternatives for remaining additives. To date, the company has eliminated 25% of the additives used in frac fluids in most of its shale plays.
But the truth of the matter is that the science and data have always been on industry’s side in this debate. So technology is less of a consideration in removing opposition than are efforts to educate the public about the science and data.

James Stafford: How important is technology versus acreage to a company’s success? How does this balance work out for Breitling?

Chris Faulkner: Given our size, Breitling’s focus on technology actually provides leverage for our investors against the huge scale of effort and capex that larger companies employ in amassing vast leaseholds in today’s resource plays. We rely on advanced exploration technology to help us find prospects others might have overlooked and help us be more selective in high-grading the best opportunities. For example, 3D seismic surveys—and earlier 3D surveys in particular—often contain information that is beyond visual resolution and thus escapes the interpreter. Signal processing on the workstation using what might be termed “geologically based seismic deconvolution” has the potential to enhance the resolution to the point that this hidden information can be made visible and incorporated into the interpretation. Breitling’s patent-pending Geo3D Seismic Filtering technology takes existing 3D seismic data and enhances it so that it is noise-free with a broad enough “zero phase” spectrum to represent fractional match points that could lead to oil and gas discovery. Within the limitations of the seismic data we can use this synthetic data to optimize our 3D data set and locate oil and gas reservoirs that were missing in previous low resolution interpretation.

James Stafford: There have been a number of hints by the Obama administration that the US could become a net gas exporter, with potential exporters eyeing lucrative Asian markets. What will this mean for gas prices at home? What will it mean for the US economy?

Chris Faulkner: I think this has gone beyond the “hints” stage with the administration recently approving a second LNG export terminal, although I expect more of that LNG will go to Europe than to Asian markets. The US would experience a net economic benefit occurring with unrestrained exports. Certainly US gas prices would increase but not nearly as much as EIA’s earlier study concluded, because global competition among established LNG suppliers would put a cap on US LNG exports at a certain price point. The US trade balance will improve. All energy-intensive industries combined would see a loss of jobs or output no greater than 1% in any year. If anything, putting a cap on LNG export volumes would probably push gas prices higher because it lessens that competition emerging in an increasingly global LNG trade.

James Stafford: Chris, thanks for taking the time to speak with us – hopefully we will get a chance to speak later in the year. For those of you looking to find out more about Chris and Breitlings operations please visit: http://www.breitlingenergy.com

Source: http://oilprice.com/Interviews/Will-Saudi-Arabia-Allow-the-U.S.-Oil-Boom-Interview-with-Chris-Faulkner.html

Interview by. James Stafford of Oilprice.com