Tech Talk - Production, Profit and Projection

As we move steadily through the first month of this new year, US production of crude has continued to increase, with the EIA now showing levels of around 8.2 mbd production.

Figure 1. US Domestic Crude production through the end of 2013 (EIA TWIP)

Finished gasoline production has been floating around a level of 9.2 mbd.

Figure 2. U.S. Finished gasoline production at the end of 2013. (EIA TWIP)

At the same time ethanol production continues at around 0.9 mbd.

Figure 3. U.S. Ethanol production at the end of 2013 (EIA TWIP)

US gasoline demand, on the other hand, has fallen below 9 mbd, in the normal seasonal decline during the winter months.

Figure 4. US gasoline demand at the end of 2013. (EIA TWIP)

In the latest Director’s Cut of the news from the North Dakota Department of Mineral Resources the state reports that production averaged 973 kbd in November, up from 945 kbd in October). The rig count is running around 190 rigs (below the all time high of 218 – roughly 18-months ago) and the agency notes that companies are moving toward a higher density for horizontal wells as a means of enhancing oil recovery. They estimate that at the current rig count there will be enough work under this program to sustain the industry for more than 20-years. However production will decline as the richer spots are drained, and in the most favorable scenario production will rise for another 2 to 3 years before stabilizing and then declining. At present the rate of growth in production is in the range of 300 kbd per year.

Figure 5. North Dakota Oil Production – historical and projected (ND Dept of Mineral Resources )

This is roughly similar to the growth in production from the Eagle Ford Shale in Texas over the past year.

Figure 6. Changes in production from the Eagle Ford Shale in Texas (Texas Railroad Commission )

Growth in production from the deep waters of the Gulf are likely to be closer to 50 kbd. Even combined, and recognizing that there may be some additional production from developing shale prospects, it is difficult, as the above three regions hit production peaks in the near future, to anticipate that US production will increase by the 2 mbd that is projected by some forecasts.

Some of this doubt comes from North Dakota agency itself, which has some concerns over the continued ability of the industry to attract drilling capital, as well as the impact of additional regulations. This limit of available funds is something that Gail Tverberg has pointed out in a recent post. Shell is only one of the major companies recognizing that the increasing costs of development in more difficult parts of the world are not being offset by compensating increases in production, price and profit. As operations around the world continue to attest, (offshore Brazil being but one example) just because the money is invested does not mean that production will of a certainty arrive on the original date forecast, nor will it be at the original price estimated. In the case of Brazil, while new fields show the promise for the future with a steady increase in the reserves that the country projects, this has yet to be reflected in increased production.

Figure 7. Growth in projected reserves offshore Brazil over the past 30 years (Offshore )

The problems of development are being blamed on a lack of available drilling rigs as well as budget constraints. This may be a considerably simplified version of the realities which are likely to continue to see delays in production against target figures into the medium term future. This is unfortunate since there remain few places where global production can be expected to increase in the near future.

In the latest Monthly Oil Market Report (MOMR) OPEC notes that non-OPEC supply growth is anticipated to be 1.2 mbd this year, with the bulk of that growth coming from the United States, Canada, Brazil and the two Sudans. Oil production from the Canadian oil sands is anticipated to reach 3 mbd by 2015 on its way to a total production estimate of around 6 mbd by 2035, at an approximate growth rate of 100 kbd per year.

Figure 8. Anticipated growth in Canadian oil production (NEB )

Perhaps more than most the Canadian growth is likely to follow the projected path, although there, as in other parts of the world, the need to ensure future capital for the increasingly expensive operations, and the provision of sufficient infrastructure to handle the increased production are matters that will continue to provide caveats to the overall levels achieved.

And as regards the increase in production from Sudan and South Sudan, certainly the conditions in South Sudan are not encouraging to hopes for increased production at any time in the near future. Fighting in the regional capital of Malakal shows the increasingly tribal nature of the conflict and this may well indicate that fighting will not easily be stopped and order (let alone oil flow) restored. This is of concern to China, which imported some 14 million barrels of oil from the region in 2013 but is now faced with the problems of sustained investment in the face of lost production and facilities after seeing a similar collapse in production from Libya. And while these problems are considered relatively small at the moment, at this time when global production and supply are relatively closely tied, the continuation of problems will mean the China must look elsewhere for that production, with consequent impacts on overall prices.

The problem, as the very short list from OPEC illustrates, is that there are not that many places around the world where increased production is likely and where China can invest to achieve the levels that it anticipates that it will need as demand continues to grow. And as the market becomes more competitive, so prices are unlikely to decline much (apart from regional short term issues such as the recent desire in the US to produce more diesel from refineries). Yet while this will give some reassurance to those seeking to invest capital in the industry it comes at a time where there remain concerns over regulation in some countries, and conflicts in others both of which cause investors to hesitate in their commitment. The problem is that there aren’t that many alternative strategies that hold much hope for working.

The end of the rowing sagas

Earlier this month I had noted that there were a couple of boats trying to row/sail down the Northwest Passage. It turns out that my awareness of the number was off by a number of boats - there were several others that I was not aware of.

However the ice came early and with darkness approaching, and the days and nights getting colder, both the two that I was following - the Arctic Joule and the Fairmont's Passion ended their attempts at Cambridge Bay. In both cases this was about half-way along their intended route, but among other things early encounters with ice slowed their progress, and they both called it quits yesterday - coincidently arriving at Cambridge Bay within hours of one another.

Sail World notes that there is 60% more ice in the Arctic this year than there was at this time last year, and that both ends of the Northwest Passage are, therefore, already blocked trapping those trying to make it through.

Figure 1. Locations along the Northwest Passage.

I have taken the Sail World map and added the position of Cambridge Bay and the two target end points for the ventures. The Arctic Joule was heading for Pond Inlet, while Fairmont's Passion was aiming for Resolute Bay. I suspect that news stories commenting on this indication that the Arctic is clearly not ice free will be somewhat sparse. And few will note that the Inuit made it a thousand years ago, establishing the Thule colony in Greenland from their origins in Alaska.
There is really nothing else to say.

Rowing the Northwest Passage - Part 2

The rowers that I have been watching as they seek to traverse the Northwest Passage are currently making good progress and have just crossed from the Northwest Territories into Nunavut.

Figure 1. Position of the Arctic Joule on Saturday evening, August 10, 2013.

What I had not realized is that they are not alone in this sort of venture. Coming just behind them now is a Norseboat, Fairmont’s Passion, in which just two men are using both oars and sail to try roughly the same passage.

Figure 2. Position of Fairmont’s Passion on Saturday evening, August 10, 2013

At present they appear to be less than 30 miles apart, with the laggard moving a little faster at present, due to the wind.

The ultimate path of the Beyond the Circle team ends in Resolute rather than Pond Inlet, so it is a shorter trip, but already one with some adventure.

Figure 3. Beyond the Circle Route.

The adventure came last Sunday when the boat entered Amundsen Bay and encountered stiff winds and pack ice. At that point they met the yacht “Anna” which was sailing from Alaska to Greenland, having made the reverse trip several years ago. After meeting yet a fourth boat, this one going the other way that warned of ice, Anna and Fairmont’s Passion struggled through that ice in Franklin Bay while sailing through a thick fog.

They are now out of the ice, and enjoying beautiful weather, making 30 miles in the last day.

Let’s hope that they have good fortune!

Crossing the Northwest Passage by Boat

I have always been fascinated by those willing to prove their point by actually going out and doing something. It does not necessarily mean that I agree with their point, but one has to recognize their willingness to put themselves in danger to validate it. Thus I have been caught into watching the travails of the four folk who are currently trying to row through the Northwest Passage.

Figure 1. Planned passage of the Mainstream vessel “The Arctic Joule.”

One of the wonders of modern technology is that the passage of the four men in a rowing boat can be updated, at intervals as short as ten minutes, as the crew battle across the northern coast of Canada. Their goal is to row from Inuvik at the Mackenzie River delta to Pond Inlet, across the coast from Greenland.

The boat is an especially designed rowing boat where the four men take shifts of 2 rowers at a time (on up to 4-hour stints in good weather, 20-minutes in bad) to move along the route.

Figure 2. Boat Movement on Friday.

The reason for my interest in this apart from monitoring the passage of folk through truly dangerous conditions where they are navigating through ice-laden waters in fog, and with the wind rising, is that they are seeking to show that boats can now make the passage. What I found particularly of note in their recent passage is that, on Friday, they dropped in on a group of beluga whale hunters.
Note this post has been updated twice, with the latest (saturday night) raising the question as to whether the row is being abandoned. (Later) However, though they did backtrack for a while, they later resumed their voyage.

It is particularly interesting in that the visit to the whale hunters relates back, a thousand years to when the Inuit made the same passage from Alaska chasing the bowhead whale. (It should be recognized that this reason for the move has been challenged). However the current tradition of hunting the beluga whale seems to overcome many of those objections.

The more prevalent view that the Thule Inuit moved across the northern coast of Canada chasing the migration of the bowhead whales is evidenced by the use of whale bones in providing the rafters for their dwellings.

They arrived in Greenland as one of the waves of immigrants that came in concert with the warming periods (earlier groups had arrived during the Roman Warming Period – the Dorset- and the preceding Minoan Warm Period).

Figure 3. Passage of the Thule Inuit from Alaska (Canadian Museum of Civilization )

They were thus in place and the succeeding arrivals fought the earlier arrivals and the Vikings who showed up around 930 AD and who considered the natives to be skraelings.

Both of these arrivals suggest that the Northwest Passage was more open, and freely accessible in those earlier warming periods that it remains today,

The current difficulties in terms of wind and ice floes are making it hard for the current team of four healthy men to make the passage, and they have had to drag their boat for a number of miles already, rather than face the conditions offshore.

Consider then that a thousand years ago the tribes brought their families with them, and made the long migration using the umiaks of the time. The archeological evidence mainly relates to the passage of the Thule Inuit, but the experience of the current team, though praiseworthy in its intent, does perhaps hint that conditions were somewhat easier a thousand and two thousand years ago, in what might have been the warmer waters of those times, when something other than rising carbon dioxide levels warmed the Earth.

UPDATE (Saturday 12:38 pm) - There is now a video up that shows that they are stuck on a beach surrounded by ice and with heavy seas, so that they are waiting where they are until the conditions improve. This has happened before and is putting them well behind schedule.

Figure 4. Boat onshore surrounded by ice. (Mainstream Last First)

UPDATE 2 - 11:13 pm Saturday. I wonder if they have perhaps given up - since the recent track tonight shows them heading back along their earlier route.

Figure 5. Boat track as it appeared on Saturday night (Mainstream Last First)

UPDATE 3: No they were just getting some headroom, and the voyage is now continuing, although it looks as though they are being driven back by a tide or some local condition, after making good progress.

Figure 6. Boat position as shown at noon on Sunday.

Tech Talk - The latest Canadian oil spill

Time was that I used to write, on Sundays usually, a Tech Talk over at The Oil Drum where I would try and explain some of the technical issues involved in oil recovery from the ground. Now that the site has effectively gone away, and I have had my couple of moments of frustration trying to explain why it isn’t because of the end of the Peak Oil story (here and here), the need for the occasional technical explanation still exists, and I still enjoy the chance to explain something. So as time permits and the need arises I will continue the practice.

On this occasion the post is seeded by a note from Luis de Sousa (h/t Luis) who noted a story in Mother Jones. That story, in turn, fed from one in the Toronto Star and is about surface contamination of oil, coming from the underlying tar sands and emerging as a watery bitumen mixture over at least four areas in the Cold Lake region of Alberta. The story is difficult to report, since the contamination is centered within the Cold Lake Air Missile Range, where the Canadian military fires and tests live weapons. Unfortunately, as written, it seems to have some technical inconsistencies.

The oil migration was apparently started by underground extraction wells that are being used to extract the oil from the oil sand, without having to dig it up first. There are two main ways of injecting steam through wells down into the oil sands that can produce the oil. The one that is most commonly discussed is the Steam Assisted Gravity Drainage (SAGD) process, but the more commonly one used in the past is often known as “Huff and Puff.” I have described both of these in some detail in an earlier post. In this case the process would appear to be the older one, and as a refresher, here is what I wrote about it a couple of years ago.

Surface mining of oil sand can only progress so far before the gradually deepening seams of the sand become too deep to continue to economically mine them. At the same time the viscosity of the oil is such that it does not flow easily to a conventional type of a well. This is not a new problem for the oil industry, which has had to address issues with the quality of the oil that it finds coming out of a well more than once over the past decades. One of the more easily applicable methods for improving the flow characteristics of the oil is through heating it. (And a quick caveat, the quantities of heat that I am talking about at the moment are significantly different from those that are needed in treating oil shale, and I will come to that topic in a couple or three weeks).

The example of the effect that temperature makes on the ease with which a fluid flows that always first comes to my mind is of a visit to the Nurse’s cabin north of Montreal one winter, a long time ago, when after struggling through waist-high snow, we sat and poured whisky from a bottle left there, as we waited for the wood stove to heat the cabin. When we started the Scotch poured as though it was a heavy syrup.

Viscocity of an oil is something that we usually only think about when we buy the engine oil that we put into the car on odd occasion. Buying the right oil means either looking for the little label that has the right description or reading the manual to get the number. But the oil that we buy for the engine is rated in part on how it behaves at different temperatures. We want the oil in the engine to easily circulate around the parts, and lubricate them from the time that we switch the engine on. But if the engine starts cold, and the oil is too thick, then it may not move easily around the parts, which may run dry for a while and wear more rapidly – which is not good. However if the oil becomes too thin once the engine reaches operating temperature then it doesn’t act as a good lubricant, and again engine wear is increased. And so manufacturers of the oil will adjust the contents, depending where in the country they plan on selling the oil, and what the temperature variations the oil can expect to operate under there. (And this is why oil is sometimes bought with two numbers – as in 10W-30 – the first number relates to the cold start, and the latter the performance at the engine operating temperature. And the higher the number the more viscose the oil is under those conditions.)

A typical oil found up in the oil sands of Alberta is much thicker, and more difficult to flow under normal operating conditions than that used in a car. For the areas of the province that are too deep for surface mining the temperature is not affected much by the changes in surface temperature, but the ground temperature is still low enough that the oil is very viscose, and production from a normal vertical well is usually too slow to justify the expense of putting in a well.

So how can the viscocity be reduced? For a simple example, take an apple, which has fallen in the butter, and you want to clean it off. If you take the apple and put it under a cold stream of water the butter sticks to the apple, but if you raise the water temperature, suddenly the butter melts and runs off the apple. This happens best at about 185 degF, and if you were to turn a pressure washer onto a greasy surface you would find that it works better if the water is also heated above that temperature. (Some pressure washers are sold that way).

Think now, if you will, of little Johnnie (helped of course by Jessica) having raided the orchard and spread butter onto all the apples, gluing them together and filling the kitchen full, right to the ceiling. How do we clean the butter off and get it back without taking all the apples out and cleaning them one by one (which is sort of what they do with the surface mined oil sand up in Canada).

We could just stand in the hall and stick heaters up against the wall of apples, hoping that the heat would melt the butter and work its way back to the ones further into the kitchen. That sort of works, but burns the local apples and doesn't reach all that far. (They have tried setting fires inside oil wells, and we’ll get to that maybe next week). You could fill the kitchen with hot water, but while that washes out some of the butter, a lot of the heat goes into the apples and the water is cold before it reaches the back of the room. And the water doesn't have that much pressure to push the remaining butter off the apples.

What we need is something that will get through the gaps between the apples and keep its heat. So how about steam? So you go and get a steam cleaner (such as you use for carpet cleaning) and blow the steam into the apples. That works but as the butter starts to flow out it clogs the gaps and starts to re-harden except when the steam is right there. So you start to run the steam for a bit, stop and collect the butter that comes out, run the steam for a bit, etc. You can do this in an oil well and it has the exciting technical name of "Huff and Puff" (would I kid you?). To make the steam more effective it is heated to between 150 and 300 deg C. Where the rock is very permeable and the steam can, in time, work its way back through the particles (apples) this can recover a lot of our butter. But you still lose a lot of heat, which is expensive to generate, just in heating the apples.

The NETL shows how the process works, in three steps:
Huff

Soak

Puff - The 3 stages of the process as illustrated by NETL.

The problem is that this is still limited by the length of the borehole through the deposit, and because it is an intermittent process, it doesn’t give a continuous flow of oil.

In the current case at the Primrose Oil Sands project this particular leak came up under a body of water making it more difficult to control, but it was the fourth at the Primrose site, though earlier ones were in the Primrose East development. In their public statement on the issue Canadian Natural stated:

This spring bitumen emulsion was discovered on the surface and based on all the evidence gathered to date, we believe this rise to surface involves mechanical failures of wellbores in the vicinity of the impacted areas. A complete review is ongoing.

The location of the latest leak under a body of water seems a little hard to support that conclusion – though I am not that familiar with the project history.

What I do remember, however, from lectures that I have given on ground freezing when teaching ground control, was the great difficulty one can have in controlling the path of any fluid injected into the ground. I mentioned some of that in a post I wrote on permeability, some time ago. The gas used in the ground freezing is usually liquid nitrogen, and it is injected to freeze the ground around the injection point and along the path that the fluid takes. (In other words the reverse of that used in steam heating of the oil). But it has proved to be a very difficult process to control, because any small fissure in the ground can have a sufficiently lower permeability that the surrounding rock that all the fluid will flow to that channel. This is particularly a problem in the case of the oil sand, because if the steam finds an easy path to the surface (and the fact that this is the fourth instance suggests that the particular oil formation may be prone to such fissures) then as the steam migrates it heats and softens the bitumen so that it will flow with the steam, widening the channel and, over time, making the situation worse, if steam continues to be injected.

Fortunately, with the “Huff and Puff” steam is only injected for a short while, before injection stops and the oil recovery phase begins. Yet, in the latest case, that was sufficient to bring over 4,000 bbl of bitumen to the surface. It seems likely that the process will need to be modified to give better control to the steam paths, and the oil migration. This can probably be achieved by switching to the SAGD process, which is planned in later work at the project. In the interim they might want to steer away from using the technique in regions where the oil grade is higher, and there is the potential for the sand to outcrop or come close to the surface without a confining cap rock.

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.

The Keystone pipeline - A Canadian response

Well that didn’t take long! (With a hat tip to Art Berman). I mentioned at the end of the last post that the loss of the oil market through postponement of the Keystone pipeline would not sit well with Canada. The delay in the pipeline removes at least temporarily sales of some 600 kbd of Albertan crude from the Canadian inventory, with the concomitant losses to provincial and national government revenue.

Speaking in Hawaii, the Canadian Prime Minister (who met with the Chinese President while on the island) said:

“This does underscore the necessity of Canada making sure that we’re able to access Asian markets for our energy products, and that will be an important priority of this government going forward,”

And to emphasize the point, while the Canadian Finance Minister has noted that the pipeline plan itself might not survive the delay. TransCanada Corp, who were to operate the pipeline has to retain its customers, even as the Finance Minister flies to China to market energy exports, and perhaps sell the available supply to China. And in the broader scheme of things:

Canada will seek to join a new Asian trade block as it tries to increase energy exports to the region following the U.S. decision to delay approval of TransCanada Corp.’s $7 billion Keystone XL pipeline, Prime Minister Stephen Harper said.

To recap from the earlier posts in the OGPSS series on Canadian pipelines there are plans by Enbridge to build a “Northern Gateway” pipeline from the oil sands to the West Coast. And this has already found support from China. Given the irritation that the United States has just provided the Canadian Government it is worth repeating the comment by the President of Enbridge:

I challenge any of you to name one other country in the world that only has one market for its largest export. Right now our most valuable resource is landlocked in North America and isolated from the world market. That means it is often isolated from world price. The August spread between West Texas Intermediate and Brent Crude, the world price, was $22 per barrel. Canadian heavy crude has more often than not sold at a discount to U.S. light crude that goes well beyond the quality differential – simply because of lack of market.

It should not be forgotten in this debate that the greatest objection to the pipeline seemed to come from Nebraska. Lest you forget Nebraska is the largest producer of corn ethanol west of the Mississippi River. It has 34 ethanol plants, converting 769 million bushels of corn a year into 2 billion gallons of ethanol. (The equivalent of 130 kbd out of the national production of around 900 kbd).

Official map of the planned pipeline from the Department of State.

TransCanada Keystone Pipeline, LLC (Keystone) is proposing to construct and operate a crude oil pipeline from Hardistry (Alberta), Canada to Patoka, Illinois (view map of project). The pipeline will be able to deliver 435,000 barrels per day (bpd) of crude oil to existing terminals in Missouri (Salisbury) and Illinois (Wood River and Patoka). The system capacity could be expanded in the future up to 591,000 bpd.

The proposed project includes 1,073 miles of new pipeline in the U.S. (Keystone Mainline). The Keystone Mainline will be comprised of 1,018 miles of 30-inch diameter pipeline from the Canadian border to Wood River, Illinois and 55 miles of 24-inch diameter pipeline from Wood River to Patoka, Illinois. Keystone may also construct an additional pipeline segment from near the Nebraska-Kansas border to Cushing, Oklahoma consisting of 291 miles of 30-inch diameter pipeline.

OGPSS - Pipelines and Eastern Canada

I wrote, last time, about the projected pipelines that are being anticipated to take advantage of increased production from the oil sands in Alberta, Canada with the intent that I would use that to lead into a review of the oil sands operation itself. However Gail has raised the issue of the proposed reversal of the pipeline (Line 9) that runs from Sarnia in Ontario to Montreal so that oil would flow to the Suncor refinery in Montreal, rather than the current flow which runs the other way. (Sarnia is right by Detroit). The pipeline reversal is planned to continue beyond Montreal, to include reversing the flow of a supply pipeline from Portland, ME so that the oil from Alberta might also supply northern New England. The project has been called “The Trailbreaker” and had been postponed two years ago when demand declined.

The overall question of the relative role of exports and imports on the Canadian oil supply equation was also raised in comments on the previous post. As a result I am going to look a bit more into the overall Canadian picture, and particularly that in the East Coast, and will postpone the oil sand piece a week (sorry Neil). To begin it helps to look at the current projects that Enbridge have in mind for pipelines.

Overview of the Enbridge planned pipeline projects (Enbridge)

The Ozark pipeline, which is shown running from Cushing to Wood River was closed on Friday, Sept 30th, when the pipeline was found to be exposed as it ran across the bottom of the Mississippi River. It carries around 240 kbd and the shut down is precautionary, since there has been no leak detected.

The dark green arrow from Cushing to Houston will be known as the Wrangler pipeline and would carry up to 800 kbd from Cushing to the refineries along the Gulf, competing with the Keystone XL, which is planned to bring an additional 500 kbd down from Alberta (about 500 kbd flows through existing connections). The intent is to move the oil away from Cushing where it is proving to be a bit of a glut.

With this surplus, and the ability to move oil around the Mid-West, the need for additional feed down from Montreal dissipates, and thus the argument for the reversal of flow so that crude from Alberta can be sent back up that pipe to the refineries in Eastern Canada. At present oil comes by tanker to Portland, ME and then enters the Portland-Montreal Pipe Line (PMPL) system. The oil flows through either an 18-inch or 24-inch line up to Montreal, a distance of 236 miles, with flow then continuing to Sarnia. A certain increase in energy security would thus be achieved for the East Coast of North America, if the oil refined on the East Coast was produced in North America, instead of coming from Russia and the Middle East. At present flow would be reversed in only one of the pipes, the 18-inch, coming from Portland. At present some 200 tankers a year offload in Portland, and send around 95 kbd up to Montreal. (The pipeline came into being in 1941 to avoid exposing oil tankers moving into Quebec to U-boats).

Portland Montreal Pipe Line (Wikipedia)

If one looks at the overall flows of oil in Canada, the increasing reliance on Albertan oil can be appreciated.

Flows of Canadian crude oil in thousand cubic meters/day – (multiply by 6.3 to get kbd) in 2009 (Canadian NEB)

Canadians consume around 1.5 mbd, of which half is gasoline, and 30% diesel. I discussed their exports in the last post.

Interestingly the largest exporter of gasoline from Canada to the US lies further East, where it comes from the Irving Oil refinery in St John New Brunswick with the 300 kbd refinery shipping 75% of the gasoline it produces into the Eastern United States.

There are two other refineries in the region, the Dartmouth refinery at Halifax in Nova Scotia refines 82,000 bd of crude, largely for the Eastern provinces of Canada. The crude is off-loaded from tankers, refined and then loaded onto smaller coastal tankers for delivery.

Yet further East is the Come by Chance refinery, now the North Atlantic Refinery in Newfoundland. In its time it was one of the largest bankruptcies in Canadian history, but it now refines some 115 kbd that arrives in 320,000 ton tankers at the nearby ice-free port. It suffers from that bankruptcy in that a subsequent sale was commensurate on the product not being sold in Canada (outside of Labrador and Newfoundland), which means that the products largely ship to the United States.

Yet one must go even further East to find the oil fields of the Eastern Canada Sedimentary Basin. And unfortunately while the nearest refinery might be near an ice-free port, the fields themselves are not.

Eastern Canadian Sedimentary basins and hydrocarbon fields (Center for Energy )

The fields include White Rose which is expected to yield around 230 milllion barrels, at around 120 kbd, with a life of 12 – 15 years. First oil was in 2005.

Terra Nova is estimated at 406 million barrels. With a production of around 125 kbd it is anticipated to last 18 years. Production began in 2002.

Seasonal floating ice in these parts varies from 1.6 to 5 ft thick and an average wind speed of around 20 mph. also leads to ice buildup on the tankers and superstructure making it a consideration in operations, as are icebergs. (Remember the picture of the tug pulling an iceberg). That was taken around here.

Hibernia is also producing at around 126 kbd, and by August 2010 had produced 704 million of the 1.4 billion potentially recoverable oil from the field, Approval has now been given to extend development to the south.

Current plans to develop Hebron, some 6 miles N of Terra Nova include also the fields of West Ben Nevis, and Ben Nevis. Production is expected to begin in 2017, at a rate of around 150 – 180 kbd of oil and 200 – 350 kbd of water. Reserves are considered to be in the 400 – 700 mb range.

Although these numbers are significant, and will provide for a considerable fraction of the need in this part of the world, and further south, they do not constitute the promise of sustained increased levels of production that are required for significant help against the declining production seen in many of the worlds major oilfields. For some help in that direction it is necessary to head West. And so it is time for the review of the oil sands.

There is however, considerable controversy over the operation of the oil sands in Alberta, particularly from those objecting citing the mess that is made of the landscape. In general the illustrations of oil sand operations that are used, show the site during mining, where the black color of the sand tends to make for a dismal picture. It might be more informative to show what the sites are like afterwards. And so, as a prelude to more discussion, here is a photo of some reclaimed land. It is here that the wood bison (as opposed to buffalo) roam.

Reclaimed land after the oil is removed from the sand (CAPP )

OGPSS - Pipelines through Canada

If one looks at the countries that are major importers of oil into the United States, Canada currently easily tops the list exporting 2.085 mbd of crude (2.524 mbd of total petroleum products) for example in June. Interestingly Saudi Arabia was in second place at 1.164 mbd and Mexico had fallen to third place at 1.108 mbd. In light of the countries that used to occupy places on earlier lists and no longer do, it is worth noting that places such as Chad and the Congo are now on the list.

Top 15 countries sending crude oil to the United States in June (EIA )

Since that summary review Canada has gone on to post some of the highest volumes of the recent past:

Weekly imports of crude from Canada into the United States (EIA)

This increase has occurred as the amount imported from Mexico has seen some of its lowest numbers.

Weekly imports from Mexico into the United States (EIA )

The numbers suggest a growing importance for that oil coming from the North. It was, for example, interesting to note that in the recent report reviewing available United States oil and natural gas, authored by the National Petroleum Council, (which I discussed earlier) and which had Daniel Yergin as Vice Chair, that Canadian oil has begun to get counted with that of the United States in the more generic classification of North America thereby acting as an anticipated aid in solving some of the “domestic” supply problems in the near future. Following that report, Dr Yergin wrote an article in the WSJ denouncing the idea of peak oil. Euan Mearns has provided his usual detailed and well-argued rebuttal to this (as does this entire series) so I will not go into that further at this point.

I briefly looked at Canada when I was writing the earlier summary posts on the top 30 producers in the world, Looking at the reported and projected production for this year, production is anticipated to steadily climb once the summer months have passed.

Production of Crude Oil and Equivalent in Canada in 2011 (Canadian National Energy Board)

The increase reflects a steady increase in the component from Western Canada, which started the year at 91% of the total, but is anticipated to reach 93% by the end, largely on the basis of an increase in production from the bitumen of the oil sands.

In passing it should be noted that not all the oil that will come from Canada necessarily started there, since, for example, there is currently a move to lay a pipe that would carry oil from the Bakken formation in North Dakota and Montana through Saskatchewan to the Enbridge terminal in Manitoba, and thence to refineries in the United States. Further not all future Canadian oil exports can be assumed to come to the United States. Two pipelines also being proposed are to run the 727 miles from Bruderheim, Alberta to Kitimat in British Columbia. The first of these would carry an average of 525 kbd west, while the second would transport back some 193 kbd of condensate, which would help to thin the crude going through the larger pipeline. Not surprisingly this $6.6 billion project is getting considerable support from China.

Not that this would be a totally new investment by China in Canadian oil,

Earlier this year, for example, five companies signed up for so-called firm service, or guaranteed access, to a portion of the Trans Mountain pipeline, which carries oil from Edmonton to a port at Burnaby, B.C. Among them is PetroChina International (America) Inc., a subsidiary of Chinese energy giant China National Petroleum Corp.

The investment is not just in the pipelines to get the crude to China, there has also been a growth of Chinese acquisitions of shares in the companies extracting the oil. Recognizing that, in contrast with many exploratory operations, the presence of the oil in Alberta is much more certain, the risks of investment are reduced and a return, or in this case the oil itself is a much more certain outcome. As a result there are now more Asian companies entering the oil sand business.

It is not unwelcome news in Canada. Bear in mind that at present 99% of Canadian oil exports go the United States, and as the President of the Enbridge Northern Gateway noted recently:

I challenge any of you to name one other country in the world that only has one market for its largest export. Right now our most valuable resource is landlocked in North America and isolated from the world market. That means it is often isolated from world price. The August spread between West Texas Intermediate and Brent Crude, the world price, was $22 per barrel. Canadian heavy crude has more often than not sold at a discount to U.S. light crude that goes well beyond the quality differential – simply because of lack of market.

In perhaps the same way as they acted to provide a second market for the natural gas of Turkmenistan (other than Russia) thereby allowing the Turkmen to be able to sustain higher prices, so now they can, to some eyes, be seen to be riding to the rescue of Canadian prices.

And then there is the controversial Keystone XL pipeline set to run from Alberta down to Houston and refineries south, and which is generating some high-level opposition.

Planned route for the Keystone pipeline

There are some current indications that the State Department will approve the pipeline, permission needed since it crosses an international border. It may not hurt those chances that the chief lobbyist for TransCanada was, apparently, the deputy manager of Secretary Clinton’s 2008 campaign. The latest step by the opposing forces has been to challenge the permit that TransCanada has to carry out construction on the Canadian side. Apparently the delays that are holding up the start of construction of the 700 kbd pipeline have carried the project beyond the year during which TransCanada had permission to start construction, without such construction beginning. On the other hand TransCanada are pointing to preparations for river crossings and the laying of foundations for oil storage tanks as evidence of such construction.

It is expected that with this increased demand production from the oil sands will double by 2020. This expansion is not without demands of its own, since the use of natural gas in the mining process (see earlier posts) will lead to an increase in demand from 1.1 bcf to 3.0 bcf to help in that production gain. And so I will take another glance at the plans for the oil sands in the next post in this series.
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OGPSS - The top 30 oil producers, a review

These posts have been going through the EIA list of the top oil producers in the world, over the past few weeks, I thought I might just review them collectively, but briefly, before starting to look at individual countries and oilfields. Even the posts that I have written recently have become out of date with new information (Russia increased production again in February by 20 kbd over January reaching 10.23 mbd) and then fell back to 10.2 mbd in March but at this stage, rather than focusing on such details, I am trying to generate a sense of the overall picture. It should also be recognized that I am just grabbing a snapshot of data, rather than the more detailed studies that look at the longer term, which folk such as Rembrandt, Rune and Euan provide. The simplest way to do this is to place my current estimates of production for the top 30 oil producers that I have reviewed in this series against the EIA estimate of their production in 2009.

Top 30 oil producing countries (those increasing production over 2009 are shown in red). (Click on the table to enlarge it)

It is significant to note that while Saudi Arabia was producing 8.05 mbd of crude in 2009, this has risen to 8.869 mbd on average for February as the Kingdom increased production to match the shortfalls in oil exports from Libya, inter alia. (With roughly 1.8 mbd in “other liquids” this takes total KSA production to 10.67 mbd and moves it back to the top of the League. However those numbers were from the March MOMR, which reports on February, In that report Libya was still being recorded as producing around 1.3 mbd). It is now reported that overall OPEC was not able to match the Libyan decline in March, falling about 350 kbd short, while KSA production has now reached 9 mbd, (10.8 including other liquids).

Contrary to President Obama’s recent remarks the EIA are anticipating a decline in US crude oil and liquids production over the next two years, part of which has been blamed on the change in GOM regulations. As a result it would be optimistic to anticipate much more than a US production of 8.3 mbd (and the EIA project it will be down to 8.2 mbd next year). It is unlikely that US production will increase beyond that point.

US crude and liquid fuels production – (EIA )

With China, Iran, and Canada holding relatively steady in the short term, this gives an updated total of 39.83 mbd for the top six, which is about 1.4 mbd higher than when I wrote the initial post back in February, but 500 kbd below the EIA estimate for their 2009 production. (While Russia and the KSA increased, the USA and Iran declined). Of these it is likely that only the KSA can continue to increase production much more.

In the second tier, Mexican production continues to fall, and was down to 2.556 mbd in February, with reports that it will now be an oil importer well before 2020. Exports have already fallen to 1.23 mbd, which does not bode well for customers. The United Arab Emirates (UAE) have, like the KSA, increased production to help out, though so far this has only been up to 2.394 mbd from 2.3 mbd for most of last year. (They also produce roughly another 500 kbd of other liquid fuels). By 2020 they should be able to produce up to 3.5 mbd. And in similar vein Kuwait, now producing at 2.368 mbd, up from 2,3 mbd. Kuwaiti plans are to reach 3.5 mbd by 2015, and be at 4 mbd by 2020.

The current political turmoil has even persuaded Venezuela to increase production, with OPEC reporting levels of 2.39 mbd for February, a gain of around 100 kbd. Though how long that is sustained depends on the success of the many investors that have been persuaded to invest in the Venezuelan oil sands.

In the third group Norway is declining, being now at just over 2 mbd, and even though it has just announced a major new discovery that will not come on line for at least 5 – 10 years, and in the meanwhile production will continue to fall. Norway needs more discoveries similar to this, however, to be able to sustain production levels extending into the future, since without them production will collapse.

Brazil was touted, by President Obama in his remarks about the Energy Blueprint last week, though the increasing volumes of oil that they will produce remain foreign to the United States, and though they will likely increase production up to around 4 mbd by 2020, rising domestic consumption may well take much of that increase.

Which brings us into the states that has some political turmoil. Iraq has been able to bring production back to around 2.64 mbd (according to OPEC) with the hope of reaching 3 mbd by the end of this year. At the moment about 1.2 mbd of this is exported. One of the great questions of the decade is just how close to a projected 10 mbd by 2020 that Iraq will be able to get. Sadly the continuing conflicts there, though reduced in scale, make it difficult for me to see much beyond 5 mbd by 2020.

Nigeria, which has had its own internal conflicts for some time, is going to the polls as I write this, and the expected winner is planning to overhaul the oil industry. However, if stability continues, then it might be possible to resurrect some of the older fields and perhaps increase overall production by some 350 kbd.

Algeria, which has had some turmoil, but may emerge from the ongoing protests without much change, is producing around 2 mbd of liquids. That has not changed as OPEC has moved to match the decline in volumes from Libya and other countries facing protests, and may reflect the current maximum that the country can produce. In the stability stakes I suspect that Algeria may survive without much change, although the plot I put up from Energy Export Databrowser does suggest that production may have peaked.

Algerian oil statistics (Energy Export Databrowser)

Angola is currently producing 1.7 mbd but may add some 650 kbd this year, for a total of 2.35 mbd. And that brings us to Libya, where the increased fighting, particularly over the oil refinery town of Ras Lanuf, makes it increasingly unlikely that the 1.7 mbd which came from Libya will be available again soon.

The United Kingdom is in significant decline, but recent moves to further tax the oil industry have made it possible that the decline may steepen. This because the new taxes proposed will likely reduce the profitability of the field developments proposed, discouraging their development. Recently production has run at 1.35 mbd of liquids, which is scheduled to drop to 1.3 mbd this year, and 0.94 mbdoe of natural gas, anticipated to fall to 0.85 mbdoe this year. The criticality of investment is shown in the projected production over the next 5 years, with the different colors showing the likelihood of success. Note that the grey of current production is declining at about 10%.

UK Projected Oil production (2011 UK Oil and Gas Activity Survey )

UK Projected Natural Gas production (2011 UK Oil and Gas Activity Survey )


Moving to the next tier down, Kazakhstan is now at 1.6 mbd and slowly increasing production toward a target of 3 mbd by 2020. Qatar is running at 1.4 mbd, but with almost 0.6 mbd of that in NGL. Indonesia is producing right around 1 mbd and may maintain that in the short term. It is being challenged in rank by Azerbaijan which has just incremented up to 1 mbd, a volume that is expected to continue to rise until it reaches about 1.25 mbd in 2014.

The tier that lies below 1 mbd starts with India, which is currently holding a production of around 878 kbd, and having to import increasing amounts of oil to meet demand. Given that the country also subsidizes the price, this is becoming an increasingly expensive consideration for the government. India is followed by Argentina, which is post peak and declined to 0.76 mbd most recently. Egypt is similarly declining, now to 660 kbd, but as one of the early nations to change under the most recent protests, and with the situation still somewhat fluid, it is difficult to predict how much the country will have both for itself, and for external customers, a year from now.

Oman will likely weather the current storms, and is also increasing oil production, to the point that it is moving up to pass India, with an Omani production of 863 kbd, some of which is tied to NGL production.

In the final four that produce more than 500 kbd Malaysia is barely maintaining production at 700 kbd, while Australia has fallen from 588 kbd to 540 kbd. Both are now being passed in production by Colombia, one of the “hotter” places for development at the moment, with production rising to possibly 920 kbd this year. Ecuador, which closes out the top 30, has recently increased production from 485 to 504 kbd.

That completes the top 30, and accounts for some 76.7 mbd of production. Those same countries back in 2009 were reported by the EIA as producing some 79.23 mbd of oil. Remember that world demand is anticipated to increase by somewhere between 1.4 and 1.6 mbd this year, and that of this list of 30 only 13 increased production, and the rest declined and the concern for the future becomes thus more clearly defined. (The difference between the two totals is partially explained by the loss in Libyan oil - we will see within the month how well OPEC covers that).

But it is not the overall production from the world that can be estimated that accurately, but by looking at individual countries and, in some cases, individual oilfields that we can get some better sense of what is to come. So the next step will be looking at these nations in more detail, in the weeks ahead.