Tech Talk - Of production stability, peaks and the future

Jeffrey Brown (Westexas from TOD) is quoted extensively in Kurt Cobb’s recent piece that points out that global crude production has pretty reasonably stayed constant at between 64 and 67 mbd since 2005. (H/t Nate Hagens). While there has been a total increase in the total refined products side of the house (with the total number floating around 90 mbd) this includes a number of different sources that, within generally defined standards, are not considered crude. The four main culprits that he lists are biofuels, natural gas plant liquids (NGLs), lease condensate and refinery gains. He makes a good point.

Figure 1. Crude oil production alone over the past decade (Kurt Cobb)

I can remember that it was some years ago, when looking at the OPEC reports on production, that I suddenly realized that the projected increases in NGL production made a significant difference in the overall volumes that they were producing. (It is anticipated to average 5.95 mbd in 2014). Back in 2001 OPEC just defined the fluid as natural gas liquids, but went through significant revisions of numbers in 2002 and in March 2004 redefined the volume counted as “OPEC natural gas liquids and non-conventional oils”.

Figure 2. NGL and unconventional oil production by OPEC (OPEC MOMR )

Over the past decade volumes have almost doubled. In the United States, with the increased development of the shale gases, production has also increased.

Figure 3. Increase in production of NGL in the United States (EIA )

The price obtained for these fluids, however, falls below that of conventional gasoline. For example:

Figure 4. Relative prices of NGL fuels relative to crude and gasoline. (EIA)

The EIA is reporting a continued growth in US production:

Altogether, in the Bakken, Niobrara, Permian, and Eagle Ford, oil production is expected to increase by 70,000 bbl/d in May 2014. The monthly growth rate is 3,000 bbl/d more than in April 2014 due to solid gains in Permian rig count and continuous rig productivity gains across the regions. While the DPR does not forecast weather impact, the spring thaw season has officially started in the Bakken region and may disrupt some drilling activity between now and June.

These additional resources take on an increasing importance as world demand is anticipated to increase another 1.14 mbd this year, slightly up on this year’s figure. This gain in demand was largely offset by increased production from the Americas, though OPEC note that overall global suppliy decreased last month to average 90.63 mbd but is expected to reach peak demand in the fall, at 92.24 mbd.

Looking at the supply side for this year, and bearing in mind that gains must more than offset lost production if the total increase in supply OPEC are projecting an overall gain in supply of 1.34 mbd, largely to come from outside of OPEC. This is expected to come from the OECD Americas (the USA, Canada and Mexico) group, while the increased production from countries such as those of the Former Soviet Union is expected, to rise by 150 kbd or less.

There has been relatively little change in the estimates of where the increases in North American production are anticipated to come. By the end of the year US production is expected to reach 12.45 mbd by the last quarter of the year. As OPEC noted:

Based on the US Energy Information Administration (EIA)’s monthly oil production report for January, regular crude oil output registered at 4.93 mb/d, tight oil production increased to 3 mb/d, NGLs output reached 2.64 mb/d and biofuels and other non- conventional oils recorded the highest output at 1.22 mb/d. The use of energy from biomass resources in the United States grew by more than 60% over the decade between 2002 and 2013 — primarily through increased use of biofuels like ethanol and biodiesel which are produced from biomass. According to the EIA, biomass accounted for about half of all renewable energy consumed in 2013 and 5% of total US energy consumed.

This month the OPEC MOMR focused on increased production from the Gulf of Mexico, with anticipated gains from the Olympus project at Mars B.

The total gain in production from the Gulf is currently anticipated to increase, this year alone, to perhaps 1.55 mbd, and to pass the previous record Gulf production of 1.8 mbd by 2016. In addition the Cardamom project is expected to add 50 kbd to the Olympus figure, and the start of oil production from Phase 3 of the Na Kika field is expected to add an additional 40 kbd to the 130 kbd which Na Kika is currently producing. However Gulf wells have a habit of going south a little earlier than predicted and I have borrowed the following graph from Ron Patterson which illustrates the cumulative fate of the combined Atlantis, Thunder Horse, Tahiti and Blind Faith fields.

Figure 5. Changes in production from major Gulf of Mexico fields over time (Ron Patterson )

When this is combined with Dennis Coyle’s prediction that the Eagle Ford field will peak in 2015, at 1.4 mbd, with a declining rate of production increase as one reaches that peak. Similarly the number of wells that can continue to be drilled in North Dakota in the sweeter counties of the state are limited, and beyond that there is a concern (which I have expressed before, and which others have explained much better than I) that as the estimates of production fall in the less successful regions of the state that it will become harder to raise the capital for the new wells needed to sustain and increase production.

That being said, I am beginning to suspect that this may be the year that the OPEC estimates for US production may get a bit ahead of what actually is produced. And if that is the case, then that means that the following two years will become even more interesting as the nations of the world start to realize that yes, there is a peak. Which might mean that the coal resurrection might be greater than I currently anticipate, but perhaps I will have more on that next time.

Hurricane ISAAC and the Gulf Coast

The political world is waiting patiently for Tuesday, when the Republican National Convention is officially getting under way, after a postponement due to the nearby passage of what remains Tropical Storm ISAAC. The question that begins to arise, however, is as to whether the political news will be swamped by the consequences of ISAAC’s arrival.

Figure 1. The current prediction for the path of Tropical Storm ISAAC, as it skirts Florida, on its way to the Gulf Coast.(National Hurricane Center)

It has been some 7 years ago that the three hurricanes of 2005, DENNIS, KATRINA and RITA, did a number on Gulf oil production. We have, in the interim, perhaps become a little complacent about the impact of a major hurricane on Gulf oil production. It was DENNIS which did such damage to the Thunder Horse platform back in July of 2005, that it took several years to bring it back into operation. (video here ). DENNIS shut in some 1 mbd, but for only a short time.

Figure 2. The Thunder Horse platform after Hurricane DENNIS in July of 2005. (Youtube )

However it was followed by KATRINA and RITA, so that, between the three of them they covered not only the swath of the ocean that included most of the drilling platforms in the Gulf, but also, as they moved inland, a significant number of the refineries on which the nation has come to depend.

In the seven years since then, the lack of significant hurricane impact on the Continental United States has led to some complacency as to the vulnerability of the country to the hurricanes that have, from time immemorial, threatened these shores.

But it is worth just a quick reminder that the impact is not just seen in damage on shore, grievous though that may become. (I was on a survey team that was one of the early groups that went down the delta after KATRINA). Already platforms are being secured:

The Bureau of Safety and Environmental Enforcement says 39 production platforms and eight drilling rigs have been evacuated as of Sunday. That's about 6.5 percent of the 596 manned platforms and 10.5 percent of the 76 rigs operating in the Gulf of Mexico. . . . . . . The bureau says operators estimate that about 24 percent of the current daily oil production and 8 percent of natural gas production has been cut off.

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The paths of the storms are somewhat different. KATRINA came in more directly from the south:

Figure 3. Path of KATRINA in 2005 (Central Florida Hurricane Center).

The path of ISAAC is currently anticipated to be more direct, as shown in Figure 1, but there are several things to bear in mind, as we move into this week.

Figure 4. Platforms along the Gulf of Mexico (FOX 4)

Firstly it was not only the platforms themselves that caused the problems in the United States after the hurricane season of 2005. There are a lot of refineries around the NOLA area that were damaged at the time, and which have not moved since.

Figure 5. Refineries around New Orleans in the region of the KATRINA hurricane track.

Hopefully between then and now the relevant refinery will have got all the switchgear that gave them problems back then out of the basement and into a less flood-threatened location.

As far as the people that live in the region are concerned, there are two additional worries. The first is that there is some thought that the hurricane may strengthen beyond a level 2, and KATRINA was only at a level 3 when it hit in 2005. The second is the direction in which the storm is approaching. While KATRINA had the full length of the delta over which to lose power, if ISAAC swings in from the East then it will pose a greater threat to the levees because it will impact Lake Ponchartrain.

If the storm tracks west of New Orleans, a storm surge into Lake Ponchartrain could push water against the city’s still-fragile levee system. If the storm makes landfall east of New Orleans, northerly winds on the west side of the storm could still create wave and water problems for the Crescent City. A landfall east of New Orleans could also bring a devastating storm surge onto the Alabama-MIssissippi coast.

. As a precaution rigs and platforms have been put into a protective posture, which has reduced daily oil production by 24% and natural gas production by 8%.

Until the full nature of the threat develops, however, it is thought that the refinery fire in Venezuela may have greater impact, although it is being reported that the damage there was constrained to just two storage tanks. (Not that this is as big a concern to the United States as it used to be:

In the first five months of 2012, the United States imported just over 50,000 bpd of fuel from Venezuela, down from nearly 290,000 bpd in 2005, according to data from the U.S. Energy Information Administration.

And for the people of New Orleans and particularly those in the ninth ward, I hope that this time they have not dredged next to the levees, nor have they left any of the barges less than totally secured.

And, lest the Democratic Party start to feel too superior, there are rumors of another Tropical Depression that might make it more interesting in Charlotte, in early September.

OGPSS - A recap with some updates on North American production

This series of posts has just completed a review of the different regions of Russian oil production, with the conclusion that while Russia may maintain current production levels of around 10.4 mbd for a short while, it faces rising domestic consumption levels at the same time that it is not replacing existing production at a fast enough rate to be able to sustain exports. Without more investment than is likely available, the rate of new field development (given the harsh and remote nature of the sites) means that there will be a slow decline in available oil to the market starting fairly soon. (Given the large supplies of natural gas that are coming available, this series is going to focus a bit more on oil as we continue the review).

As the series continues, and moves slightly down the list to consider the future of the oil and gas fields in Saudi Arabia, it is worth noting that while there is little that Russia can do to significantly raise production in the short term, that does not hold for the desert kingdom. However, before moving on to KSA in detail, this week is a pause to consider some contextual changes in the overall picture.

One of the questions that has been raised many times relates to the reality of the true maximum production levels that Saudi Arabia can achieve. As oil prices have continued to rise politicians are calling for the Saudi’s to increase oil production, so that the price may fall. (This is a rather odd and unrealistic request when the KSA needs all the income it can get to help domestically.) The EIA, in considering the global oil flow as sanctions begin to bite on Iran have projected that OPEC has a spare capacity of 2.5 mbd, most of which comes from KSA. At present the KSA is producing at around 9.7 mbd up some 600 kbd from this time last year, according to the EIA, although there is a little question as to how accurate that number is. (The IEA is reportedly saying that KSA is already producing at 11.5 mbd.. However the IEA counts all liquids, as Gail has pointed out, while EIA values are for the crude and condensate, which add up to 9.7 mbd, so that while there appears a discrepancy there really is not). The debate is likely to see some harder numbers in the months ahead. Iran is already having problems marketing their oil, since after January 23rd the European Mutual Protection and Indemnity Club is no longer covering shipping contracts. This is making it difficult for consumers such as India to maintain supply, and they are already considering the use of sovereign guarantees for its shipping lines. At the same time the EU is not calling for coverage to be phased out until July 1.

The EIA report notes that Iran is currently the 5th largest producer of liquid fuels at 4.1 mbd, although it consumes 1.8 mbd of that internally. Thus the threat to the global market runs at around a 2.3 mbd reduction on current overall demand of around 88.1 mbd. The series will discuss Iranian production, and its prospects somewhat later, but before getting into an analysis of Saudi Arabia, it might be worth just a quick glance back at a couple of countries that have been covered earlier.

Estimates of future production are only that, and, as has been noted in comments on recent posts, not all anticipated production or plans work out as anticipated. To give but a few examples pointed out in comments, and elsewhere:

The Russian oilfield at Yuzhnoye Khylchuyu was initially estimated to hold 505 million barrels of oil, but has now been reported as only having reserves of 142 mb.. (Noted by voiceinyourhead) On the other hand the Sarmatskoye field in the Caspian is now considered to have double the original estimate, and is estimated as just under 1 billion barrels of oil equivalent in natural gas and condensate. It is anticipated to come on stream in 2016. And, while on the topic of natural gas, both toolpush and RayRay have noted that the natural gas from Sakhalin Island is not going to see the 3rd LNG train that I mentioned in the post on that topic, and that the natural gas will instead feed into a pipeline to the mainland.

In regard to the posts that were written to cover the United States and Canada, the February monthly flow of oil through the Alaskan pipeline has fallen to an average of 609,805 bd. This is down from an average of 624,716 bd in January and gets the flow closer to the point where solidifying wax and water start to cause problems.

In the time since the posts were written on North American production and promise (politically including Canada with the United States makes the overall change in production figures look better than if the figures were based solely on US production, particularly as oil from the Albertan oil sands rises to production levels of 3 mbd by 2015) the Canadian National Energy Board (NEB) released their “Canada’s Energy Future: Energy Supply and Projections to 2035” report. In seeking to predict future production the NEB anticipated that the price of a barrel of oil would rise relatively modestly over the next 20-years. Even in their high estimate they do not see the price rising to more than $160 a barrel by 2035 (who would bet that the estimate is exceeded this year or next?).

Canadian estimate of the future of crude oil prices (NEB )

The report estimates that in the Reference case, oil production from the oil sands will reach 5.1 mbd in 2035, which is three times 2010 production. This will be mainly from in-situ methods.

Canadian crude oil production (NEB )

Over the ten years from 2010 to 2020 in-situ production is anticipated to grow at 9% p.a., while mining production will rise at 5% p.a. The North West Upgrader is anticipated to come on stream in 2014, with an initial 50 kbd of throughput. Carbon dioxide produced during the process will be used in Enhanced Oil Recovery (EOR) locally. If the price rises to the highest levels anticipated, then production might be estimated to rise to just under 7 mbd in total for Canada by 2035.

Canadian production for different case estimates of price, as above (NEB

However the NEB do recognize that domestic consumption will affect overall supply, but consider that it will likely only significantly impact the lighter crudes, and that the difference between the roughly 4 mbd of heavy crude produced and the 3.8 mbd available for export in 2035 will reflect a relatively constant 0.2 mbd of internal consumption.

Canadian light oil future predictions (NEB

With considerably more oil, therefore, being available from Canada, albeit there remain concerns over how much will be shipped to the USA, there is somewhat less pressure on domestic producers. Which is likely good news since the likelihood of US production remaining at current levels is still doubtful.

One of the hopes for the future comes from the wells being drilled in the Gulf of Mexico, with DoE projecting that gulf production will rise to some 2 mbd by 2020, from 1.3 mbd at present.

One concern that remains however, lies in the actual levels of production that will be achieved. As Jean Laherrère has noted the wells in the deep water have not all held up their promise, peaking on average within a year of coming on line. Jean notes that the production decline with the Mars and Ursa fields are at about 9% per year, which he notes is less than half the decline rate at Thunder Horse. Darwinian is also tracking production, and although he notes that Tahiti is performing relatively consistently at 110 kbd, Atlantis is not coming close to the 185 kbd projected.

Atlantis production (Darwinian )

Exploration and development in the Gulf are, apparently now back to pre-Deepwater Horizon levels, one can only hope that future developments will be less dramatic and more successful.

The speed of that recovery is encouraging, though the results to date have been a little less promising than anticipated. But, as with operations in the Arctic, investment costs are going to be high for any new finds that are viable, and will take a number of years to develop, at a time when demand is going to continue to increase. The Gulf discoveries, for example, will likely start to come ashore about the time that the Bakken and Eagle Ford plays start to fall in production, and thus, overall, may not give the boost to American volumes that are currently being projected.

OGPSS - gas flares, their significance in Russia

Over the weekend I went to a talk on the promise of shale oil and gas, given by Sid Green, a friend and one of those members of the National Academy with Washington influence in regard to the future of the fossil fuel business. (He appears much more a Yerginite than a follower of Matt Simmons, as was evident by his conclusion that the fuels from the shale deposits of the country will be our short-term savior. This is a proposition that I have provided some evidence to doubt). However it was in his introduction, by Joseph Smith, the new Laufer Chair of Energy at MS&T, that a slide appeared that is useful to preface where this, the Tech Talk series, will go next. This is the slide:

A poster from NOAA showing the light emitted at night from city lights (white), fires (red), boats are in blue and gas flares are in green. (The picture was put together over the period from January to December 2003.)

It was that large green blob sitting just below the Yamal Peninsula in Russia that caught my eye. It shows the volume of stranded natural gas in Russia that is being flared off because it is stranded, i.e. there is no current way to ship it to market.

UPDATE: I have changed the end of the post to reflect a written answer to my question from Sid Green.

Interestingly, given that preponderance of flaring in Russia, one can also go to a paper given at a Russian meeting where the more ubiquitous size of gas flaring operations around the world is more evident.

City Lights and gas flares around the world, data collected In 1994-95. (city lights in grey, flares in red).

As I noted in a recent post on developments in the Bakken shale, up to 30% of the natural gas that is being produced with the oil is being flared at the moment because there is no way of getting it to market. (And in 1994, note the amount being flared in the North Sea). It is not just a problem for large wells, For many years I drove between Rolla, MO and Crane, IN, spending the night in Vincennes, usually arriving late, with my drive through Eastern Illinois illuminated by flares from the small stripper wells along the way. And it is possible to see flares from the rigs operating in the Gulf of Mexico.

Gas flares illuminating the night in the Gulf of Mexico (NOAA)

In the past Gregor Macdonald has also documented the flares that are found off the coast of Nigeria. . And there was some suspicion that these represented the greatest volume of gas being burned off in this way.

Flares around Nigeria color coded by duration, Those active in 2006 and 2000 are yellow. Those active in 2000 but not 1992 or 2006 are green. Those active in 1992 but not 2000 or 2006 are blue. (NOAA )

A 2007 survey, carried out by NOAA for the World Bank, showed that Russia was burning roughly twice the volume of gas as that lost in Nigeria. A close look shows how the plumes from the flares dominate the Siberian night-time sky.

Thermal plumes from gas flares in Siberia

The NOAA report indicates that around 160 billion cubic meters of gas is flared each year, roughly a quarter of the volume of natural gas that is used in the United States each year. And while countries such as Nigeria have been able to reduce the amount that is flared, countries such as Russia, Kazakhstan and Iraq have increased the volumes flared. (It also explains how the images above were generated). The region of Russia with the most gas flaring is that around the Khanty-Mansiysk region, which accounts for roughly half the Russian total. In 2007 a conference on the subject heard that Russia was flaring around 50 bcm per yer, with Khanty-Mansiysk contributing 24 bcm of this total. (The gas is flared because this is currently where about half of Russia’s oil production is coming from). At that time the goal was set that, by the end of this year, (2011) some 95% of this natural gas should be utilized. There have been a variety of ways suggested to reach that goal. Again, putting the volumes in context, Russia commercially produced some 600 bcm of natural gas in 2006, as well as some 10 million barrels of oil a day.

Flaring around the Khanty-Manysiyski region south and east of Yamal. (World Bank)

At present Russia has reached a new peak in crude oil production of some 10.34 mbd for October, while Saudi production is estimated to have risen to 9.8 mbd. Russia is thus the current largest oil producer, and so it is time to look at where (other than just the region shown above) the oil is coming from, and what the prospects for the future hold for the longer term production, and export of energy from that country.

The natural gas production picture is not quite that rosy, even with the reduction in gas flaring that has been undertaken. Gazprom is reported to have reduced supply as prices in Europe have risen towards $15 per kcf (thousand cubic feet), almost four times that of gas in the United States. Russia as a whole produced some 1.8 bcm/day (63 bcf) of which Gazprom produced 1.35 bcm, both figures down from the same time last year. At the same time domestic consumption of natural gas has risen by some 1.3 bcf/day. Russia supplies about a quarter of European demand, and as production falls off in some of the fields of Western Europe that portion may increase. However the global supply of natural gas is still quite healthy with countries seeking to find domestic sources from the gas shales that might lower their import needs. Thus the power that Gazprom was able to wield just a couple of years ago has now been somewhat reduced.

All of these factors strengthen the conclusion that this series should now move to look at some of the fields in Russia, and given that Dr Yergin has proved to be a better historian than prophet, that probably means that I should go away and re-read The Prize, before it starts. (Though The Quest is an easier read). After all, one wonders how many of us, a week ago, could have found Khanty-Manysiyski on a map?

Location of Khanty-Manysiyski on a map of Russia (Google Earth)

In passing, Secretary Salazar has just announced that permitting will allow the Natural Buttes Project to move forward. Anadarko are expected to develop up to 3,675 wells in the Uintah Basin over the next decade to supply more cheap natural gas into the market, and likely keep the price pressure on the production of gas from gas shales. Which brings me full circle back to the opening of the post, since the question that I asked Sid at the presentation was “How long can the gas shale companies afford to sell their gas at under $4 per kcf, when it is costing them more than this to produce it?”

UPDATE: I had a short snippy version of Sid's reply here, but he was kind enough to send a critique and deeper explanation, which gives a better answer. To summarize his answer, he feels very much in agreement with the points that Rockman has been making in comments on a number of my posts on this topic.

He notes that financing for the E&P companies has recently largely come from "venture capital" money. The companies are able to recover much of their own capex in the first months, but he was careful to note that this did not imply that they are able to make a profit. And with that return they are able to continue on the “tread mill” of drilling another well, and another . . . .

He quoted costs, and noted that a recent WSJ article said that Pioneer was reported to have costs of around $2.48 per kcf. Though if I can interject they are drilling the Eagle Ford and thus the costs may be lower for the gas, since they are, as he notes, making most of the money from the associated liquids. (And Rockman is not that excited about the general situation down there).

However he thinks Haynesville costs are up to $3.50 and Marcellus up to $4.00 or more per kcf. As a result the number of rigs might soon start falling, though he has hopes that with some technical improvements the cost figures might come under better control, and he senses that there are others in the industry also anticipating greater production at lower cost, with some of the better ideas that are being developed. These relate (HO thinks) to better control of the fracture paths induced out into the formations. But without much change operations will move over to more liquid productive areas, and the natural gas situation will not be sustainable as it is.

As an additional side comment there are now animated maps of the Barnett, Bakken and Eagle Ford plays, showing the wells drilled each year, and the production totals, under the Shale Play Development History Animationssections of the EIA map page. (H/t this weeks TWIP which is on the Bakken andEagle Ford.)

OGPSS - Governor Perry, an Energy and Jobs Plan

Editorial Comment: I usually would not consider this a technical talk, but rather more political, but I have just about finished reviewing the potential for growth of the reserves in North America. In that context, as I delved into Governor Perry's recently announced Energy Plan, I realized that it followed fairly closely the recommendations of the American Petroleum Institute, and other Energy Alliances. Given therefore that it might be considered the "best shot" of the oil and gas industry to predict how to increase oil and gas production in the United States, I will treat it more as such a plan, and have removed my own comments on this post. (Though I may make some in a following post. I am also using his numbers rather than other values that might be available))

One of the relevant (to this site) facets of the current Republican debates at the start of this Presidential Race has been the Energy Plan that Governor Perry put forward the other day. Because it actually gets specific about where some of the projected 1.2 million jobs he anticipates adding to the American economy will come from, but given that detail has not got a lot of publicity, I plan to briefly review it here, together with some of the source documents that were used to generate it. Please note that this is not an endorsement, but rather an illustration of one of the plans that have been suggested. Here is the summary illustration.

The jobs anticipated by Governor Perry’s Energy Plan

The entire plan is available, as a 40-page pdf, and in its shortest summary version was condensed into

My “Energizing American Jobs and Security” plan will commence or expand energy exploration from the Atlantic coast to the western seas off Alaska. We will end the bureaucratic foot-dragging that has reduced offshore drilling permits in the Gulf of Mexico by eighty percent. We will tap the full potential of the Marcellus Shale in Pennsylvania, Ohio and West Virginia. We will unleash exploration in our Western states, which have the potential to produce more energy than what we import from Saudi Arabia, Iraq, Kuwait, Venezuela, Columbia, Algeria, Nigeria and Russia combined.

The Governor puts current U.S. consumption at roughly 19 mbd with domestic supplies producing around 7.5 mbd. The nation runs on oil with transportation using 72% of the oil, and 96% of the countries transportation fuel needs are supplied by oil and gas.

The Governor inserts a quote from Governor Jindal of Louisiana that states:

According to a recent study by IHS CERA, in 2012 alone the Gulf of Mexico could create 230,000 jobs, increase revenues and royalty payments to state and federal treasuries by $12 billion, and contribute some 400,000 barrels per day of oil production towards US energy independence if the federal government accelerates the pace of permitting activity to a level that reflects the industry's capacity to invest.

This quote refers to the report “Gulf of Mexico - Restarting the Engine” by CERA which tabulates the difference achievable between a slow permitting environment, and an enhanced one over the next two years, and uses it (in more specific detail) to develop the summary table:

Projected gain in opportunities in the GOM with an enhanced permitting process (CERA )

(It should be noted that roughly 94% of this in 2011, 97% in 2012 and all of the 2013 opportunities would be in the Deepwater offshore.)

In looking next at Alaska, the Governor sees the opportunity to develop the National Petroleum Reserve, with its 896 million barrels of oil and 53 Tcf of natural gas, as well as the Alaskan Outer Continental Shelf, (under the Chukchi and Beaufort Seas) which may contain as much as 10.2 billion barrels. The report by Northern Economics to Shell is quoted that anticipates some 55,000 jobs around the entire country coming from the development, with some 35,000 jobs being in Alaska. (Of this the breakdown would be 30,000 from the Beaufort UCS and 25,000 from the Chukchi Sea OCS. It is anticipated that the increased production will fill the Alaskan pipeline again, with jobs being generated to make the connections. Which is why the 1.2 million job figure is only reached over time. Wood Mackenzie produced a report for API that is also used as a reference for the Governor, and it shows the job growth (broken down a little by source) as:

Growth in jobs related to changes in Energy Plans (Wood Mackenzie )

I am assuming that the increased production from Alaska would fit in the “Increased Access” category. And please note that the Wood Mac report carries out to 2030, while the Governor is only talking of the jobs through 2020 (which is the 1.2 million number).

And while the Governor is largely discussing this plan in terms of jobs, this is, after all, an Energy site, and so I will also add the anticipated change in oil production that is foreseen from this change in the situation – again from Wood Mackenzie.

Gains in Production from changing regulations and access (Wood Mackenzie )

The jobs numbers were derived as a count of specific jobs generated in the industry, and then using a 2.5 multiplier to add their effect on the general economy. (This they consider to be conservative, given that in cases it might be as high as 5). The overall addition of oil to the national reserve is considered to be roughly 60 billion barrels of oil, broken down as follows:

Anticipated gains in reserves added through changes in regulation and access. (Wood Mackenzie)

The Governor is a little more conservative in the oil that he anticipates coming from the Atlantic OCS, anticipating only some 3.2 billion barrels of oil and 28Tcf of natural gas, as well as creating some 10,000 new jobs. He references a report from the Consumer Energy Alliance as his source for some of this information. Note that, in contrast to the Alliance, he only anticipates that drilling would occur offshore Virginia and the Carolinas.

Looking at increasing production of oil in the Western States, he cites the Blueprint for Western Energy Prosperity (site registration required) from the Western Energy Alliance. This projects that some 500,000 jobs could be created, along with the production of 1.3 mbd of oil and an additional 1 Tcf of natural gas from Western Resources.

The increase in oil production is anticipated to come from the Bakken fields (currently at 289 kbd and anticipated to increase to 650 kbd by 2020, and it also anticipates development of the Niobara formation in Colorado and Wyoming which, from sensibly zero, has recently started to be developed and is anticipated to produce some 286 kbd by 2020. However the total gain in production from the two, over existing production in the West, is anticipated to be 529 kbd.

Natural gas, transported through the Rockies Express and Ruby pipelines is expected to add 1 Tcf of production, which the Alliance shows divided between the Western States.

Anticipated future gas production from the Western States (Western Energy Alliance )

The Alliance makes the point, as does the Governor, that reaching these levels requires a reduction in legislation, and regulation, and improved access to federal lands.

Approval of the Keystone Pipeline (a topic of current debate) is expected to add 20,000 new jobs, which only leaves the allowance of increased development of the Marcellus and Eagle Ford shales (dependent on the allowed use of fracking the shale) to add respectively 250,000 jobs in the New York, Pennsylvania, Ohio region, and 68,000 jobs in Southwest Texas, and you have the Governors 1.2 million.

The jobs anticipated by Governor Perry’s Energy Plan

To achieve this the Governor proposes:

1. Immediately return to pre-Obama levels of permitting in the Gulf, followed by responsibly making more of the Gulf available for energy production.
2. Open the ANWR Coastal Plain (1002), National Petroleum Reserve Alaska (NPR-A), and the Alaskan OCS (Beaufort and Chukchi Seas) for development.
3. Open the Southern Atlantic OCS off-shore resources for development.
4. Immediately approve the Keystone XL Pipeline.
5. Expand on-shore oil and gas development in Utah, Colorado, North Dakota, Montana, New Mexico, and Wyoming, authorizing more development on federal lands.
6. Oppose federal restrictions on natural gas production, including hydraulic or nitrogen fracturing and horizontal drilling.

As I mentioned at the beginning I will make some comments on this, in light of my recent posts on North American Energy in a later post.

OGPSS - Deepwater Gulf and the presence of salt

The deep waters of the world’s oceans and seas are a frequent topic in discussions of the source of future production of oil. Having talked about the development of the offshore Gulf of Mexico oil and gas fields last time, in this post, I’m going to venture further away from the coast, and look at the deeper wells that are now where the most promising discoveries and developments are made. For the sake of reference, the U.S. Government has defined deepwater as being anything deeper than 1,000 ft. IHS (CERA) has defined it more recently as deeper than 2,000 ft, and in their projections last year had suggested that deepwater fields had the potential to contribute up to 10 mbd to global supply by 2015. This would be up from 1.5 mbd in 2000, and 5 mbd in 2009. And that would, as a “region” put it at the top of the league, in the company of Russia and Saudi Arabia.

Within the United States deepwater production is currently focused in the Gulf of Mexico (GOM) with individual oil fields that compete with state production.

Production from the Gulf Of Mexico comparing some individual platform production. ( Petro Views)

At present (August 2011) there are 27 rigs active in the Deepwater, in water depths ranging from 9,627 ft (Tobago) to one allowed in at 922 ft (GC 50). Eight of the rigs are being run for Shell. In total there are about 90 prospects being considered, while 81% of current GOM production of oil and 47% of natural gas comes from the deep waters of the Gulf.

For the three largest fields cited in the plot, Tahiti, is believed to hold 4-500 million barrels of oil (mb) started production in 2009 in 4,000 ft of water. Production is nominally some 125 kbd of oil and 70 mcf of natural gas. Atlantis lies under 7,100 ft of water and was set to nominally produce 200 kbd of oil and 180 mcf of natural gas. Thunder Horse lies in 6,050 ft of water, and even with delays due to having to do some re-engineering, is still not performing up to the anticipated 250 kbd of oil, and appears to be declining in production at a higher than expected rate. And even when the North field has been added, as Darwinian has noted, production has not been sustained at target levels.

These fields are now generating new projects that lie close to the original discoveries, Thunder Hawk, for example, lies close to Thunder Horse, and is in 5,724 ft of water with total vertical depth (TVD) of the well being 25,885 ft. It is designed for 60 kbd of oil, and 70 mcf of natural gas. Further discoveries continue to be made. In June, for example, Exxon announced a discovery in Keathley Canyon, so that even if the original potential is not achieved (and I have not even discussed fields such as Jack, which has been rated at perhaps 500 mboe) there will continue to be sustained production from the Gulf, even if it is steadily moving further offshore.

This might be a good point to slip in a little comment about salt domes. When the original Spindletop well was drilled in Texas, it was not recognized at the time that the hill from which the well descended had been formed by a salt dome. Yet once this had been grasped, the slight hills that were the surface feature of these domes became a guiding marker for wildcatting across Texas.

John Bratton has provided a little explanation of the initial history of salt in the Gulf. Simplistically, as the global pull separated North from South America it first created a valley :

The tearing apart of plates does not make an ocean right away. Usually, the big valleys first start to fill as salt deposits form, like those found in the Dead Sea in Israel and Jordan, or the Salton Sea in California. These deposits are called the Louann Salt in the area of the Gulf of Mexico. As the big crack at the bottom of North America widened, the ocean filled the big valley permanently, new ocean crust began to form, sediment began washing into the widening hole from the Mississippi, and other rivers and reefs grew along the shore, burying a width of more than 500 km of salt and the edges of the new crust.

Over millions of years, plumes of the light salt began to float up through the heavier sediment that covered it, like the colored liquid in a lava lamp. As the salt made it very close to the surface, sometimes having traveled through more than 10 km of rock and sediment, it pushed up the sea floor above it to form a mound or dome.

The driving force for the movement of the salt lies in the difference in specific gravity between the 2.19 SG of the salt, and the typical 2.7 SG of the overlying sediments. As a result, due to the plasticity of the salt, it will flow under the differential pressure and due to its lighter density preferentially deform upwards. ( This can be illustrated, for example, at the Wieliczka salt mine in Poland where miners have mined what they thought was virgin salt, only to find old mining equipment buried within the rock.) With time that upward movement pushed through and compresses overlying sediments.

Michel Halbouty has described how the Gulf salt, which can now lie some 30,000 ft below the surface, could then create the traps for oil.

Once the movement of salt begins, the forces of buoyancy are constantly at work, depending on the static weight of the sediments above the salt and on the flanks of the salt core. The main motive force of the uplift of the salt through the sediments is the static weight of these sediments, principally on the flanks of the salt core. The salt stock moves in stages through geologic time, depending on the thickness and the weight of the sediments above and around the salt mass. . . . . .
Cycle after cycle of this procedure took place until the domes gradually pierced their way through the overlying beds to their present positions under the surface of the earth . . . . . . .Some of these moved upward rather slowly, so that they could not keep pace with the rapid deposition of sediments and eventually became buried beneath many thousands of feet of overburden. These domes are referred to as "deep-seated," and gas and oil production is generally found in the arched, but unpierced, formations lying over the super-dome area. Other salt stocks, including the one at Spindletop, seem to have developed under conditions that resulted in the salt stocks remaining near the surface throughout their growth history. . . . . Gas and oil production at these domes is therefore likely to be important in the pierced formations that butt against the sides of the salt mass. It was one of these salt cores that finally settled under an area that is known as Spindletop.

It is difficult to see these deeply buried domes given the current geology of the undersea Gulf surface.

Gulf topography (Gulf Blue Plague)

Rather we have to rely on geophysical surveys where the subsea geology is plotted through the return of sound waves, allowing the rocks under the sea to be mapped in three dimensions. Using this technique it is easy to see (even in a simpler 2-D version) the presence of salt domes.

Salt migration and the effect on overlying Miocene deposits in the Gulf (after Morris via Geoexpro ) The image has been colored to enhance the features.

Similar structures extend to the East and are projected to be potential areas for future production closer to Florida. The salt does not, however, just move vertically upwards, but can also flow laterally. However, in earlier times the formations under the salt would not have been distinguishable because of the way that sound waves move through that rock. (The results have been compared with seeing through frosted glass). Thus hydrocarbons in beds below the salt would have been hidden.

Hydrocarbon reservoir that used to be hidden by overlying salt (BOEMRE )

More modern and advanced techniques have allowed formations to be seen both above and below the salt. (Or pre and post salt).

Depth section across the Florida Escarpment showing plays both above and below the salt Section width is 90 km, vertical magnification is 5:1 (Geoexpro)

As with the technology to find these deeper reservoirs so increasingly more complex drilling rigs have had to be developed to reach and develop the deposits. This included technology to drill through the salt, first carried out by Diamond Shamrock in 1983, although it was not until the Mahogany field was discovered by Philips Petroleum that commercial subsalt production began, Both Atlantis and Thunder Horse reservoirs lie sub salt.

Not all the equipment works as anticipated, and this has been evident, not only with the Deepwater Horizon tragedy last year, but in other rigs and other locations.

Hopefully now, however, the industry has learned the lessons that needed to be learned, and the permitting of new drilling means that the new discoveries that continue to be made can be developed without further loss of life.

OGPSS - Gulf of Mexico production, and hurricanes

The summer brings back Hurricane season, with the threat that such storms bring to the oil and gas well operations in the Gulf of Mexico. And the National Oceanic and Atmospheric Administration (NOAA) has noted that

The Atlantic basin is expected to see an above-normal hurricane season this year, according to the seasonal outlook issued by NOAA’s Climate Prediction Center . . . . 3 to 6 major hurricanes (Category 3, 4 or 5; winds of 111 mph or higher)

The lessons of this vulnerability were, perhaps, more than most years, evident in 2005. The first sign of problems came with the arrival of Hurricane Dennis in July. It was a storm which severely damaged the BP deep water Thunder Horse drilling platform.

Thunder Horse after Hurricane Dennis (Prof Goose)

As that season wore on, the vulnerability of the platforms in the Gulf, and the refineries that border it, were exposed in more intensity with the passage of Hurricanes Katrina and Rita. These threats and their analysis were one of the factors that helped, in that formative year, to bring an audience to the pages of The Oil Drum. The Gulf is now home to thousands of wells, which, as the evidence from the Deepwater Horizon disaster last year reminded us, has moved further and further away from shore. That vulnerability is perhaps illustrated by a map, showing the path of Hurricane Rita through the oil platforms off the Texas and Louisiana coasts.

Path of Hurricane Rita through off-shore Gulf production facilities (The Oil Drum) (Each dot is a production unit)

Back in the 1930’s and ‘40’s it was the very gradual deepening of the seabed in the Gulf, that allowed the first oil drillers to venture, through the swampy regions of the Mississippi Delta and then on out into the waters of the Gulf. There had been some drilling from piers out in California and similar constructions were also tried along the Louisiana shore, as the prospects for success tempted companies away from the coast. However, as they did so the rigs faced the challenge, as they do today, of surviving in regions where Hurricanes are not uncommon. The industry was helped in this development since there were no major hurricanes that moved through the regions of most intense drilling, from the first wells in 1945 until 1964 when Hurricane Hilda arrived. And even when that hurricane struck on October 3rd, it only damaged three locations, at Eugene Island and Ship Shoals 149 and 199, with a total of some 11,869 bbl of oil being spilled due to the storm.

Gulf of Mexico showing regional features (Geoexpro)

The first pier-based platform had been built out into the Gulf of Mexico at McFaddin Beach, south of Port Arthur, Texas after having been approved by the Secretary of War, on July 8, 1937. The pier was a mile long, with three rigs at the far end, but it only drilled dry holes and was destroyed in a hurricane in 1938. More widely recognized was the first well to be drilled out of sight of land. This was the Creole platform near Cameron, which was a mile out-to-sea, an hour-an-a-half trip by shrimp boat at the time. The water was only 18 ft deep and the well, initially drilled by Pure Oil and Superior Petroleum, (later Kerr McGee, and then Anadarko) sat some 15-ft above the water level. Initial production was 600 bd from a depth of 9,400 ft. It was damaged by a hurricane in 1940, but survived and produced more than four-million barrels since through directional drilling.

Kemnac Rig 16 drilling the first offshore well in the Gulf of Mexico (Kerr-McGee via Penn Energy)

As was the case with California there was initially some controversy over who owned the rights to minerals off-shore and in 1953 Congress passed the Submerged Lands Act, which gave the rights to the states for the first three miles offshore, (the range of a smooth bore cannon at one time) and then the Outer Continental Shelf Lands Act which gave the rights for the more offshore land to the Federal Government. This settling of the disputes encouraged further drilling and while there were already 70 rigs, drilling at depths up to 70 ft of water, the years after 1953 saw the development of a variety of different rigs for drilling in ever deeper water. Designs to cope with hurricanes also progressed, so that by the time of Hurricane Flossy in 1956 rigs were relatively safe. It was followed by Audrey in 1957, ranked as the sixth deadliest hurricane in US history, which came ashore at Cameron, and killed 416 people, but caused $16 million in damage offshore, with no fatalities.

Path of Hurricane Flossy in September 1956. (Note I have referenced the web pages showing the storm paths under the Hurricane name in that which follows).

Technology was, however, allowing rigs to work in ever deeper water, 100 ft of water in 1957, 225 feet by 1965, and 300 ft in 1969. With this increase in range came increased production, which had reached 2 mbd, but it also exposed more rigs to the threat from larger storms. Hilda, formed in 1964, caused $100 million in damage and effectively destroyed 18 platforms,; Betsy in September 1965 had the distinction of financially impacting a future President of the United States.

On September 9th, the day Hurricane Betsy struck, MAVERICK was located 20 miles off the Louisiana Coast in 220 ft of water. The following day an inspection showed Zapata’s three other rigs were undamaged, but the MAVERICK had vanished. This was the largest single loss that the domestic offshore drilling industry sustained in this or any other hurricane. . . . . .The MAVERICK loss was a substantial one for Zapata. This was our newest rig and one of our very best contracts. . .

(George H.W. Bush, “My Life in Letters and Other Writings.”) (The insurance check was for $5.7 million).

Camille in 1969 was the largest storm to hit the USA in the 20th century. It did about $100 million in offshore damage, including sinking three up-to-date rigs designed to survive those storms. (Camille was a Category 5). Onshore the damage exceeded $1 billion. This was the hurricane that taught the industry that they had to design rigs that could not only withstand waves more than 70-ft high, but has also to consider that the seabed itself might move under the force of the storm.

Fortunately such storms have proved to be relatively rare, and the “three strikes” of Dennis, Katrina and Rita in 2005 have not been repeated since. Yet the industry remains highly vulnerable to such storms. As the second figure shows, the Gulf has become increasingly filled with production platforms. In 2008 this region was hit by hurricanes Gustav at the start of September and Ike two weeks later. Even though these were weaker storms their impact was significant.

Effective August 2008, there were more than 3,800 production platforms in the Gulf, ranging in size from single well caissons in 10 feet of water up to a large, complex facility in 7,000 feet of water. The MMS estimates about 2,127 production platforms were exposed to hurricane conditions from Gustav and Ike, carrying winds greater than 74 miles per hour.

Final results of the agency’s assessment of destroyed and damaged facilities from these two storms indicate that 60 platforms were destroyed. These included some platforms that had been reported earlier to have extensive damage.

In comparison, 115 platforms were destroyed by the Rita-Katrina wallop in 2005.

The platforms designated as destroyed following Gustav and Ike produced 13,657 barrels of oil and 96,490,000 cubic feet of gas per day, or 1.05 percent of the oil and 1.3 percent of the gas produced daily.

Part of the reduction in damage came from lessons learned from Katrina/Rita.

Mobile Offshore Drilling Units (MODUs) that previously had to have eight mooring lines were now required to have 12 and, in some cases, 16 mooring lines,” Angelico said. “In ’08, 18 moored MODUs were in the path of hurricane force winds, and two went adrift, which represented 15 percent of the rigs out there. In Katrina and Rita, 63 percent of the rigs went adrift.’

There are additional impacts from these storms. The Gulf continues to produce about 27% of the nation’s oil, and 15% of the natural gas. Those fuels must be brought ashore and, in the case of oil, refined. Refineries lie inshore all along the Gulf Coast, and if flooded can take months to be brought back on line. Given the growing reliance that the country places on production from these regions makes us all vulnerable to the season.

Outer Continental Shelf (OCS) Crude and Condensate as an annual volume and percentage of national production. (BOEMRE)

Last October OCS crude and condensate production averaged 1.52 mbd, which comprised 28% of the estimated US production.

Offshore Natural gas production as an annual volume and percentage of national production (BOEMRE)

Last October natural gas production averaged 5.6 bcf/day which was 8.9% of estimated national production.

There is a significant production from smaller, older wells, while the new fields are found in deeper waters further into the Gulf, and so that is where I will venture next time.