OGPSS - Future Russian production from the Arctic

In the past few weeks I have been looking at the potential for sustainability in oil and gas production in Russia, now producing at a predicted recent peak of 10.36 mbd, when condensate is included. But the question increasingly becomes whether or not Russia can sustain these levels through this decade, as has been assumed by those suggesting that there will be no supply problems in the near future. In order to sustain this level of production, against falling volumes from the current major sources in Western Siberia (estimated as 300 kbd in 2010 ), Russia is so far relying on bringing new fields into production in Eastern Siberia and Timan-Pechora (as well as some increase in condensate as natural gas production continues to increase). However these developing fields, as a broad generalization, are at a size of about 500 mbd each, with an anticipated maximum individual production level of around 150 kbd. (Prirazlomnoye for example, which is coming on line has 526 million barrels in reserves, and will be producing at 132 kbd).

Prirazlomnoye drilling rig representation (Gazprom).

Since the high flow rates will likely not be sustained for long intervals, and declining production in Western Siberia will continue, so Russia will need to continue major programs of development to find further fields to bring on line later in the decade and beyond. In addition the declining production in other fields (which might increase overall decline in existing production to 5% or more, i.e. above 500 kbd) will add further pressure to sustain current levels, particularly given the criticality of oil and gas income to the Russian Government.

With much of the land already surveyed, the potential for large fields lies mainly offshore, and particularly in the various national continental shelves and the disputed underwater territory between them in the Arctic. It is a region where there are multi-national concerns and involvement, with the USGS having previously estimated that it is home to about one-fifth of the world’s undiscovered, but yet recoverable oil and natural gas resources, an estimate, at the time, of 44 billion barrels of oil and 1,670 Tcf of natural gas.

Map of the Arctic showing relative location of some development sites (Google Earth)

From the US perspective the US Bureau of Safety and Environmental Enforcement ((BSEE) seems finally willing to let Shell begin exploratory drilling in the shallow waters of the Chukchi Sea, although there has been a challenge to the recently awarded air Permit from the EPA. At the same time that the USGS is set to issue a new report that projects that shales on the North Slope may hold as much as 80 Tcf of natural gas and 2 billion barrels of oil, with initial drilling to prove the reserves anticipated to start this year. But those developments are on the other end of Russia, to the majority of current developments.

The recent discoveries by Statoil off the Norwegian coast and in the Barents Seas(at Skrugard-Havis, and Aldous Major South, show the potential that still remains in the North. Roughly a third of the world’s largest gas fields lie north of the Arctic Circle with Russia having significant reserves among them.

World’s largest gas fields (can you name the others?) (Shtokman )


Russia is therefore moving toward a planned program of development of the resources off its own continental shelf, where it is expected to be able to produce up to between 0.8 and 1.6 mbd of oil production and 18 to 20 bcf/day of natural gas. Part of the problem, however, is going to be cost. The new program is expected to cost some $216 billion, at a time when the investments in developing the current projects in Yamal and Eastern Siberia are also demanding large investment, if those goals are to be met.

Definitions of regions offshore (pertinent in future debates over who owns what in the Arctic) (Extended Continental Shelf Project)

TNK-BP are spending $12 billion to develop the Russkoe, Suzunskoe, Tagulskoe, Russko-Rechenskoe, and Messoyakhskoe fields in the Yamal region, with the hope that these can contribute at the end of this decade, and into the next, at a total level of around 300 kbd. Suzunskoye is targeted to begin production in 2016, running at around 100 kbd once on line. Russkoye is projected to start in 2017, and produce 150 kbd of a heavier oil. Tagulskoye and Russko-Rechenskoe will come on line in 2019. Messoyakhskoe is a joint project with Gazprom and (at $17.3 billion cost) will not come on stream until 2024, at 320 kbd. These fields will, however, feed into the pipelines that head East, to China, Japan and Korea.

Closer to Murmansk Exxon Mobil and Rosneft are exploring blocks in the Kara Sea anticipating that it may ultimately cost $500 billion to develop reservoirs in the difficult conditions with moving icebergs but for now expect that initial exploration and development will cost in the $10’s of billions.

Perhaps, of these fields it is the Shtokman natural gas field, which lies under the Barents Sea, 550 km north of the Kola Peninsula which has drawn most attention. Currently expected to start production in 2016, costs may well run over $15 billion.

Location of the Shtokman field (Shtokman Project)

Shtokman was discovered in 1988 (the name comes from Professor Shtokman who gave his name to the research vessel that found the field and contains an estimated 85 Tcf of natural gas, as well as around 400 million barrels of concentrate. It lies under 1,000 ft of water, with the interesting occasional problem of visiting icebergs that can weigh up to 4 million tons apiece. Planned to come on line in with an average production of 2.3 bcf/day, the supply (as the above map shows) half the supply is anticipated to feed into the Nord Stream pipeline for shipment to Western Europe, while the rest is converted to LNG and will be shipped out by tanker. Gazprom has recently increased the area of its license rights for the field, with a new date for commitment set for this month.

The current intent is to use a series of buoyed risers to connect from the wells to the surface, so that, should an extra-large iceberg appear the Floating Production Unit (FPU) can detach and move out of the way – should tugs not be able to divert it.

Artist’s concept of the layout for development of the Shtokman field (Shtokman Project)

The pipeline shipments are planned to begin in 2016, but the LNG shipments (some 7.5 million tonnes a year) will not start until 2017. The project is a joint venture between OAO Gazprom, Total S.A., and Statoil A.S.A.

The USGS has noted that there are considerable regions in the Arctic that have, as yet, been poorly explored. In 2005 they produced this map of the then state-of-knowledge:

Status of oil and natural gas evaluations around the Arctic (USGS)

From this they produced two maps showing the location of possible undiscovered deposits. The potential undiscovered oil deposits are shown below:

Potential oil discoveries and size remaining in the Arctic. (USGS)

The point however, is not that there is going to be no more oil, it is just, as the production schedules above illustrate, that it is going to be slow and expensive to develop that which remains. Over the next decade Russia will have to bring three or four new fields on line each year at around 100 – 150 kbd each, if it is to sustain production at current levels. It is somewhat difficult to see them being able to hold to that schedule, even for a year or two.

OGPSS - NPRA and ANWR, will they help TAPS?

When I wrote about the Alaskan Pipeline last week I noted that the pipeline was currently flowing at a volume of 495 kbd, after the Alyeska folk who run the system had just issued a report indicating that there would be problems once the flow fell below 600 kbd. Checking the flow rate for August (posted on Sept 1), the flow rate has risen back to 539 kbd, with average flow for the year to date running at 568 kbd. (The EIA reported final average for 2010 was 589 kbd)

The problems that come with low flow (including reduced revenues) are recognized within the state, and Alaskan Governor Parnell has urged that enough new wells be brought on line to allow flow to be raised back up to 1 millions barrels a day (mbd) within ten years. With the ongoing decline of current reservoirs, one has, therefore to look at the reservoirs that lie North of the Brooks Range in what is known as the North Slope (though it is rather flat) and see what can be brought on line.

It should be remembered, as a part of this, that despite talk of global warming, Northern Alaska is not a place where you can just drive a rig to a promising site and drop a new well in place within a couple of weeks. Nor has it the same level of Government scrutiny. For while the President has encouraged renewed drilling in the region, Shell, who were planning on a new program this year, have had to postpone it until next year because of an EPA concern over air quality permits. The nearest community to the planned wells in the Chukchi Sea, is some 70 miles away, and has 245 inhabitants.

Relative location of the proposed new drilling activity off Alaska

The need to find and develop a replacement for the Prudhoe Bay field and its adjacent fields is clear from the way in which the fields have been depleting.

Contribution of the different fields to Alaskan Production (Governor’s Office )

The impracticality of an immediate turn-around in the current decline is perhaps indicated by the fact that only one exploratory well will have been drilled in the state in 2011.

Exploratory wells drilled in the North Slope (Governor’s Office )

There must therefore be some incentives if companies are to drill in the future and the Governor believes that this will come about with a change in the tax incentives from the State. This need for some incentives is particularly true given the cost of operations that far North. Shell, for example, has spent close to $4 billion so far and has yet to start development. It is also expensively seeking to ameliorate some of the concerns raised after the Deepwater Horizon disaster.

Shell is proposing to use two drill ships, each capable of drilling a relief well for the other in case of the kind of blowout that destroyed the Deepwater Horizon rig. The company is also promising to add more testing and an extra set of shears to its blowout preventers and to keep emergency capping systems near drilling sites to capture any potential leaks.

But disregarding the politics, there is the question of how much oil is there?

The USGS has often given estimates of the technically recoverable resources that can be found in a region, but in the case of the North Slope they have taken this analysis one step further. A recent report took a review of the resources likely to be found in the National Petroleum Reserve- Alaska (NPRA) and applied some costs for the likely development of those resources, from which they came up with an estimate of the likely economically recoverable amount of oil that the NPRA holds. The analysis, both of what is there, and its likely extraction cost, included some 30 exploration wells, not previously considered. The analysis is also statistical in that, without actually drilling the rock, they can only estimate the likelihood of how much oil and gas are there. However one thing that the exploration wells showed is that a lot of what was thought to be oil in the reserve is actually gas. Further that the reservoir quality is worse than originally estimated. When the two are combined the estimate of the likely oil to be found and recoverable fell from 10.6 billion barrels of oil (bbo) to 895 million barrels of oil (mbo), of which some 500 mbo are likely to be economically recoverable. (This is the mean estimate).

The USGS also considered the gas volumes present, and with no present way of getting the large quantities of natural gas that exist up there down to a consumer (and with costs likely at the moment to exceed those at which natural gas is available from other sources) they assumed that it will take at least 10 years for the gas to find a path to market. If it takes twice as long, then the amount of recoverable oil is likely to be only about 358 mbo. For a 10-year delay the mean estimate for the amount of recoverable natural gas is 17.5 Tcf (trillion cubic feet) but this drops to 7.3 Tcf if it takes 20-years to get a pipeline in place. (Note that the amount of natural gas held in the NPRA is, at the mean, considered to be 52.8 Tcf). I am not going to go into the details of either the geological estimate, or the economic analysis but these are provided in the USGS reports. It is interesting, however, that they used a 12% decline rate (which they defend). The news about the condition of the reserves has apparently led some companies to relinquish their assets in the NPRA.

On the other side of Prudhoe Bay lies the Alaskan Wildlife Refuge, and particularly that part running along the coast which has been designated as ANWR – 1002, or, more comprehensively, the ANWR Coastal Plain. Just North of the Coast lies Camden Bay in the Beaufort Sea, and it is here that Shell has just had permits approved for four exploratory wells that should be drilled next year.

Location of the ANWR Coastal Plain, relative to Prudhoe Bay ( ANWR )

For the Coastal Plain itself, the USGS last updated their assessment in 1999, and using the mean values (the others are given in the report) considered that the technically recoverable oil in place would be 7.7 bbo out of a total 20.7 bbo in Area 1002. If one assumes that the same sort of economic criteria apply to ANWR as applies to the NPRA, then one might assume that roughly 55% of that technically recoverable might be also economically recoverable, for a total potentially available therefore from ANWR as being around 4.3 bbo. However it may also be that the same changes in both the reservoir rock and the type of hydrocarbon present may occur in ANWR as in NPRA, and if that comes to be the case, then the economically recoverable oil may fall to 10% of the current estimate, or around 430 million barrels. Not to be sneezed at, but not nearly as promising a number as has been discussed in the past.

More detailed view of the 1002 Area (USGS via planetforlife)

While these numbers are still somewhat speculative, until a bit actually drills down to the rock, and validates what is really there, the conclusion that is likely more critical at this time is that it is unlikely that there will be enough new oil coming into the pipeline in the next few years to stave off continued decline, and potential pipeline closure.

I had planned on writing about drilling in the Arctic and development and the off-shore fields, however I will put that off until next time.

OGPSS - The oil and gas of Southern Alaska

Before it was American, Russian visitors had already noted the presence of oil seeps in Alaska, although they had not done anything about it by the time the tsar sold the land to America on March 30th 1867. Russian history would have it that some $165,000 of the $7.2 million of the sale was used to persuade doubting American legislators and members of the media of the value of the purchase. The oil can still be seen, coming from current seeps, such as this one:

Natural oil seep, Oil Creek, Alaska (David Page )

These seeps occur both on and offshore, and as happened in the rest of the country, it was these seeps that brought prospectors to the region, and where the first wells were drilled.

Location of natural seeps along the Alaskan coast. (after David Page and the Copper River and Northwestern Railway )

It is pertinent to note that the creeks shown above are productive salmon spawning grounds, though it was the oil that led to early development.

The first producing field was at Katalia on the Gulf of Alaska. Discovered in 1902, it produced 154,000 bbl of oil before the refinery burned in 1933.

Early Drilling rig at Katalia in Alaska (Cook Inlet Oil and Gas )

The larger fields in and around the Cook Inlet began production with the development of the Swanson River field in 1957. The first Alaskan pipeline was built in 1960 to carry oil from there to the Nikiski refinery (which later supplied the fuel to the International Airport in Anchorage. The Cook Inlet fields peaked in oil production, at 227,400 bd, in 1970. The largest oil field in the region was the McArthur River field, discovered in 1965, but while discoveries continue to be made, the majority of the wells are now past their prime, and will need significant work to be brought back into production. The more recent developments were offshore, with a considerable change in structure from that of the early days.

Unocal Monopod platform in Cook Inlet (Cook Inlet Oil and Gas )

Fields (oil is green, natural gas is red) in Cook Inlet, Alaska (Alaska Department of Natural Resources via Cook Inlet Oil and Gas )

In 1958 natural gas was discovered in the Kenai Peninsula, and by 1962 was supplying gas to Anchorage, 85 miles away. There was sufficient natural gas available that, in 1969, a liquefied natural gas (LNG) plant was built and began shipping LNG to Japan, the first such export from the US to Asia. By 2009 some 1300 tanker loads, with an original deadweight capacity of 36,896 tons, had been shipped through that train.

There were two original tankers on the run, the POLAR ALASKA and the ARCTIC TOKYO, partially made of balsa wood and invar steel and they made the twenty-one day round trip until 1993, when they were replaced by the POLAR EAGLE and the ARCTIC SUN, each with a deadweight of 87,000 metric tons. The ships were renamed POLAR SPIRIT and ARCTIC SPIRIT at the end of 2007, when the registration was moved from Liberia to the Bahamas. They were sold to Teekay Corporation at that time, but leased back for the duration of the project. With the declining production from the plant, the ARCTIC SPIRIT was returned to its owners in April, 2009.

The recent drop in the price for LNG on the world market, meant that the POLAR SPIRIT was returned to its owners at the end of this past April, with the end of the original charter. It now appears to be shuttling between Yokahama and the China Sea, with the last call in the US being in June. The LNG facility was mothballed at the beginning of this summer since Alaskan LNG was no longer competitive on the market.

the plant received needed license extensions last year, but was not able to get a satisfactory price for their LNG. . . . . . business case does not support continuing exports at this time.

The original two LNG carriers were renamed SCF POLAR (which left Las Palmas a couple of days ago) and SCF ARCTIC which left Point Fortin this morning.

The region has never been one of intense activity, with only a relatively few wells being drilled in any one year.

Exploration wells drilled in the Cook Inlet region of Alaska since 1950 (Oil and Gas )

At present there are two jack-leg drills heading for Cook Inlet, with the state providing some of the funding ($30 million) for this new drilling activity.

The wells that have been drilled and brought into production in the past have produced, to date, around 1.3 billion barrels of oil, 7.8 trillion cubic ft (TCF) of natural gas and 12,000 bbl of natural gas liquids in total. At the end of June the U.S. Geological Survey (USGS) announced the results of a new assessment of the resources of the region. There is a considerable amount of coal in the region, which is likely to contain methane, and this is now included.

Potential resources of Cook Inlet, Alaska (USGS )

The excluded region in the above graphic shows the coal that lies below 6,000 ft, and is considered unlikely to hold any gas. In addition to this coalbed methane, the USGS re-evaluated the likely volumes that are held in the sandstone and conglomerates that have, to date, been the host rocks for the oil and gas that has been extracted. Finally the USGS assessed the potential of tight sands in the region to hold technically recoverable volumes of gas.

As the recent experience with natural gas has shown, just because a resource exists, and can be recovered, does not mean that it will make sufficient money to justify the investment in the extraction. Thus the USGS can only say that there is a significant likelihood of oil and gas being present and recoverable, without bringing the costs and price of the fuels on the market into the discussion, and thus defining whether the resource is, or will be a reserve, or not.

Because the volumes are estimates, they vary from there being a 95% chance that there is some 5 Tcf of natural gas available, to a 5% chance that there is 39 Tcf of natural gas present. In the same way they estimate that there is a 95% chance of 108 million barrels of oil (mbo) being present, while there is a 5% chance that there might be as much as 1.3 billion barrels. Unfortunately current prices are not necessarily that favorable to much exploratory drilling to validate some of those numbers, though obviously they are favorable enough to convince the Governor to put up some money.

But another part of the reason for this lack of interest has been because of the much larger volumes of Alaskan oil that lie considerably further North, in the region known as the North Slope, which I will discuss next time. But that is beginning to run out, and there are other problems that are apparent, so the resources further South may have thus become more attractive.

Incidentally the mothballing of the LNG plant is leaving Anchorage with a wee bit of a problem. Until this year the facility has acted as a transient storage facility from which, in periods of high demand (such as the depth of winter) gas could be temporarily withdrawn to make up temporary shortages between demand and supply from the wells in the field. That has now gone.