Tech Talk - Fast destruction and slow reconstruction

Underlying many of the projections of future energy supply that are now being made there are, as mentioned earlier, a lot of assumptions that are beginning to appear more questionable as time passes. Much of the concern has to focus on the instability in the Middle East and North African nations (MENA) that are now increasingly unsettled by civil conflict. While optimism in many reviews anticipates that the turmoil will decline and nations will return to pre-conflict levels or higher, particularly in the case of Iraq, unfortunately this conflicts with much of what we have learned from recent history. Sadly there is also the history of Gazprom, which now also suggests that rosy visions of the future are only that, and what is coming is likely to be much grimmer.

Considering first Libya, once the infrastructure of an oilfield and its links to the outside world, and the operators that run it have been destroyed, seriously damaged or dissuaded from being there, then, particularly where conflict continues over time, restoration of pre-conflict volumes can take more than a decade. Once combatants become embittered by the realities of civil war, so their willingness to subsume the hatreds and other burdens brought on by loss becomes more difficult to engage, and conflict drags on with its continued losses for society. Libya is a sad example of how rapidly production can collapse.

Figure 1. Libyan oil production pre-current conflict (SEPM strata )

The country has now reached as low a rate of daily production (around 240 kbd) as it has seen in recent years.

Figure 2. Recent Libyan oil production (from OPEC MOMR)

For some time the powers that be have continued to hope and even project that Libyan production can return to levels of around a million bd, but those hopes seem dubious at best.

Just a week ago the National Oil Corporation announced that it was lifting the “Force Majeure” designation for the Oil Harbor at Zuetina. The first tanker was to load on Friday. According to a Bloomberg report the Ottoman Tenacity was to pick up a cargo of 600,000 barrels from Zuetina and carry it to Europe. The ship was reported to be loading on Friday and is currently just off Cagliari in Sardinia.

Figure 3. Location of the Ottoman Tenacity on Wed May 7th (Marine Traffic )

A second ship was supposedly loading up to 850,000 barrels at Haringa destined for France. Yet according to Marine Traffic it is now (Wednesday) off the coast of Tunisia, and does not, in the end, appear to have revisited Haringa.

The situation in Libya is not really stable, despite the hopes. On Sunday the Parliament swore in a new Prime Minister but his support is not strong, and factions continue to challenge his election. Attacks on the military are also on the increase. Meanwhile the blockade of the Sharara oilfield continues. It is hard to see oil production increasing much above the current levels, despite the optimism.

Yet if this effectively has removed a million bd from the global market, where can this be made up? In the short term Saudi Arabia increased production to cover the shortfall, and is still producing around 9.7 mbd. OPEC production overall remains at around 30 mbd, and is projected to remain at this level over the year.

OPEC notes that the Former Soviet Union is expected to increase production by around 200,000 bd this year, of which almost half will come from Russia itself, but OPEC are careful to include a word of caution in their predictions of Russian output.

The risk to Russia’s supply forecast remains high on technical, political and natural decline grounds.

It is the increasing political risks associated with Russian production, and the supply of that fuel to Europe that are perhaps of most concern. An article in Der Speigel points out that the Russian grip on German fuel supplies is only increasing. One of the Russian oligarchs has just bought one of the German oil and gas production companies for $7.1 billion, and now controls a fifth of German natural gas production and a quarter of its oil production. Another fifth of the German natural gas market, provided by Wingas, is also now Russian as Gazprom bought the company, and its distribution network, in a sale to be finalized this summer. And while Europe is seeing more LNG receiving facilities being constructed there is still a global shortage of export facilities to match that demand. As a result current facilities are significantly under-utilized.

Gazprom has, in the past, shown that it can, when necessary, play hard ball to ensure that it owns and controls the market for natural gas (just ask BP or Turkmenistan), and with the demise of the Nabucco pipeline is in increasing control of natural gas supplies into Europe. That condition cannot change in the short term, LNG facilities take years to plan, permit and construct, and thus the control which Russia exerts over Europe through this grip on the various supply pipelines is likely to continue to influence European opinion and, more realistically, actions in the next few years.

What this all means for the future of Ukraine is rather unfortunate – regrettably it is not clear that Russian ambition will end there and one would suspect that, given the limitations in response to the current and earlier (Georgia) Russian activity, that it will not. How this will affect overall oil and natural gas supply is unclear. OPEC concerns over future Russian production levels appear justified, especially since future developments in Russia will require increasing levels of capital, which might instead be directed at supporting Russian foreign policies – reducing overall volumes available, and more particularly the volumes that Europe has come to depend on. It could make for a couple of interesting years, since there are few alternatives that can be developed within that time frame. And certainly there is, at present, little will to make the capital investments that might bring them about.

Sadly history suggests that the outcome will not be a good one, there are few precedents that would show how one might get out of the increasing messes caused by political instability.

Tech Talk - Where to look for more oil this year.

The news that Saudi Arabia is planning to employ 200 drilling rigs next year (up from 20 back in 2005) suggests that there is a recognition that future reserves may not measure up to the planned volumes needed. Plans now include exploration of the shale deposits in the country, looking primarily for natural gas. There are estimates that this resource could run as high as 600 trillion cubic ft. Current plans are to drill seven exploratory wells in the Red Sea, off Tabuk.

Figure 1. Location of Tabuk in the Kingdom of Saudi Arabia (WikiMedia )

This is across the country from the major oil fields currently in use, which lie more along the Persian Gulf coast, centered perhaps around Damman. It therefore suggests that they are looking for extensions of the Israeli and Egyptian fields into northern KSA. (Minister Al-Naimi said that they still “had to find them.”)

In discussing the venture Saudi Minister of Petroleum and Mineral Resources Ali Al-Naimi also noted that, choosing to look for – and presumably finding - natural gas, would take the pressure off the country to maintain its oil reserve.

Al-Naimi said that prospects for global production of shale gas and oil – including in China, Ukraine, Poland and Saudi Arabia – were so promising that the Kingdom might not need to continue with its decades-long policy of maintaining an oil-output cushion for use in global supply disruptions.
“It is not a question whether Saudi Arabia has spare (oil) capacity. It is a question of whether we need to spend billions maintaining it at all,” Al-Naimi said.

Now over the years KSA has lowered the volume it has projected that it can produce from 12.5 mbd to 12 mbd, and this is, perhaps, an early indication that they intend (whether by policy or natural reserve availability) to lower that maximum further.

This has to be of at least a little concern, since the number of places with significant flexibility to increase production are getting closer to zero every year. The gains in global production that are foreseen by OPEC in the next year, for example come in dribs and drabs.

OPEC notes that in May the 8,915 producing wells in North Dakota collectively produced over 800 kbd. (The Department of Mineral Resources reports 821 kbd in June, over the 811 kbd in May with well numbers of 8,932 in May and 9,071 in June. Production per well is thus running an average of 90 barrels a day, with a well cost of $9 million.) There are 187 rigs plus/minus working and this is still enough to keep production rising at a rate of 1.3% per month. One of the maps I find interesting is this, from the Department.

Figure 3. Location and production values for wells in North Dakota (Department of Mineral Resources )

It is this illustration of the relatively heavy drilling already in the “sweet spots” and the poorer performance in the less well drilled regions that gives me concern for the longer term prospects for the formations. And as an aside note that crude from Alaska is declining, July output was 498 kbd against the year-to-date average of 542 kbd. The EIA is noting that, since there aren’t any major oil pipelines running into California from the East, that there is an increase in rail traffic to make up the difference. The EIA is suggesting that the traffic is already at a level of around 100 kbd.

And this in happening in the most promising region to increase production (though it includes Canada, for which OPEC projects a growth over the year of around 40 kbd, which is set against Mexican production, for which OPEC sees a decline of around 60 kbd).

Malaysia is projected to increase production by 50 kbd, from the Gumusut field. This is a Deepwater project, and one can get some estimate of the shape of the field from the well pattern. The production gain is viewed by OPEC as likely being the highest in the region.

Figure 4. Planned Well pattern for the GUMUSUT KAKAP project in Malaysia (Rawingbadi)

In Latin America Colombia is expected to increase production by 80 kbd, though the country is having some issues with pipe damage from terrorism. There have been more than 30 attacks this year. OPEC also looks for an increase in Brazilian production of 10 kbd over the year, this gain coming after some 14 months of decline, which drop hopefully will be recovered before the end of the year.

Oman will grow production by 20 kbd, but it is in Sudan and Southern Sudan that OPEC anticipates the greatest growth, of 90 kbd. However the two countries are not the best of friends, with oil from Southern Sudan having to ship by pipeline to Sudan, for shipment onwards. At present oil, at an average rate of 75 kbd is continuing to flow up the pipe, but Sudan continues to threaten to halt shipments, leading Southern Sudan, in turn, to plan to shut-in the wells. The OPEC projection seems to be best defined therefore as “iffy.”

OPEC expect Russia to increase production by 80 kbd in 2013, yet there is some caution in that estimate, with other numbers suggesting that Russia is reaching a modern peak in production. Kazakhstan is projected to increase production by 50 kbd (coming from the startup of Kashagan, now expected at the end of September). The 100 kbd production will more than offset declines in the rest of the country. And China may increase production over the year by 60 kbd.

I have listed the countries that OPEC anticipates will grow production by more than 10 kbd, and have not listed the many countries that will see production decline by more than that amount. It is remarkable that listing the increases in production outside of OPEC can be done with just a few paragraphs. And it is a little disturbing that the threats to pipeline security throw questions over the reliability of some of the numbers. And yet this only addresses the possible growth in production, declining producers would require a much longer list. Combined it becomes a little more difficult, as turmoil in MENA continues to grow, to remain optimistic over the OPEC projections.

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.

.

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 - conditions and treatments in North Ghawar

Recent OGPSS talks have focused on the increased use of novel technology in Saudi Arabia, as a means of recovering stranded oil, left during the waterfloods that have successfully sustained production over the past few decades. That technology is being further expanded with the use of carbon dioxide injection as part of an Enhanced Oil Recovery program. The CO2 project has been in the works for some years with an initial estimate that some 40 million cubic feet of CO2 would be injected daily into flooded areas of the Ghawar field. The gas will come from the Uthmaniyah Injection Plant and will be initially injected into seven wells in the Uthmaniyah section of Ghawar. The initial flood will be monitored, since it is important to ensure that the CO2 finds the oil that it will help flow to production wells.

 Aramco have also recently announced success with changing the make-up of the injection water being pumped into the fields to sustain pressure. By altering the ionic composition and salinity of this water it has been possible to significantly increase the amount of oil that is liberated and thus recovered from the reservoirs.

 Ghawar is sufficiently large that it has been divided into different segments, and the conditions vary between them. Because of the differences between the various regions, the overall statement that Ghawar is producing some 5 mbd has to be read with a degree of caution, lest it be presumed that this has continued to be from the same regions of the overall field. (And while this article deals with oil production, it should be noted that Ghawar also produces around 2.5 billion cubic feet (bcf) of natural gas a day.)

Figure 1. Sectors of Ghawar with the date of discovery (Afifi )


Ain Dar came on line in 1951, with an initial yield of 15.6 kbd of dry oil, and the field was given the overall name of Ghawar (from the Bedouin name of the overlying pasture) in 1952. The original well was still producing 2,100 bd of oil in 2008, having, by then produced a total of 152 million barrels. Down at the other end of the field the first Haradh well was put into production in 1964, and though mothballed for a while due to lack of demand, was still also producing in 2008, at a rate of 2,300 bd – for a total production of 24 million barrels. Shedgum 1 was brought onstream in 1954, and was sidetracked with a horizontal section in 2008, which brought production back to 3,700 bd. The first Hawiyah well went on stream in 1966, and by 2008 was still producing at 4,600 bd – having by that time produced some 51 million barrels of oil. 


 Stuart Staniford and Euan Mearns have, among others at The Oil Drum, provided extensive sets of information on Ghawar over the years. For those that are not familiar with the region, Stuart’s early description is a good place to start. In this brief overview I will not get into any of the details of those descriptions, though I will quote one or two of the most relevant highlights. The debate initially focused on the amount of the waterflood in different regions of the field, since it was possible, with extensive work, to extract information on the rate that the water was advancing, relative to the remaining volumes in the different regions. For example, in one of his earlier posts, Stuart showed the following sequence of profiles for the water progression across a section of the field at Uthmaniyah. This was followed by an additional response from Euan.

Figure 2. Sections of the Uthmaniyah region of Ghawar showing the water flood progression. (Original source: Figure 12 of Al-Mutairi et al, Water Production Management Strategies in North Uthmaniyah Area, Saudi Arabia, SPE 98847, June 2006.) 

 Stuart then continued this analysis into evaluating the conditions in North Ghawar (i.e. Shedgum and Ain Dar) leading him, based on figures such as this:

Figure 3. Section through Ain Dar region, from Stuart Staniford,original source Alhuthali et al, Society of Petroleum Engineers Paper #93439, March 2005. 

 This led him to accept a prediction from Fractional Flow, who had earlier noted that production in Northern Ghawar had fallen (in 2007) from the 2mbd oil and 1 mbd water of 2003 to 300 kbd oil and 2.7 mbd water in 2007, as follows:

*90% or so of 'Ain Dar/Shedgum's 2mbpd could water out over the course of a few years. *We are likely somewhere in the midst of that process.

*That is likely the explanation for most of the Saudi production declines we have seen since June 2005 (including the failure of Haradh III and Qatif/Abu Safah to raise production).

The discussion at the time (which is still present in comments under the main papers) was fascinating, since it was based, inter alia, on information such as the speed at which the water front was advancing.

Figure 4. Speed of water front advance in North Ghawar (Fractional Flow ). 

 The use of horizontal wells and MRC came late in the development of North Ghawar, which is why the use of carbon dioxide injection for EOR, smartwater injection, induced fractures and long horizontal wells to capture otherwise stranded oil, will play a more important part in the production from the region. 

What these new technologies bring with them is the ability to go back into the older regions of Ghawar and extract some of the oil that was left in place during the original water floods. Because a number of them will be dealing with regions of the reservoir that are already flooded, so that the oil will be coming from wells with a high water cut, it is in my opinion unlikely that these will allow increases in production from the region, but rather that it will allow a sustaining of existing production levels somewhat further into the future than we (the collective wisdom of the TOD writers) have predicted in the past. 

 But Ghawar is not just the original wells of the North, and I will have more to say about the field, and then about other fields in the country in future posts.

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.

OGPSS - At around 2 mbd - Nigeria, Angola, Libya and the UK oil production

The growing concerns about the stability of the countries of the Middle East and North Africa (MENA) because they make significant contributions to world oil supply adds additional meaning to these weekly posts on the world’s major oil producers. To briefly recap I looked at the top tier oil producers (as listed by the EIA (i.e. those who produce more than 3.1 mbd in 2008) in the first post of the series. (These were Russia, Saudi Arabia, the United States, Iran, China and Canada. ) In the second I looked at the next four countries on the list, namely Mexico, the United Arab Emirates (UAE) Kuwait and referred to Venezuela – subject of a series of posts earlier in the year. The third post covered Norway, Brazil, Iraq, and Algeria. And so now we move on to look at Nigeria (2.35 mbd), Angola (2.0 mbd) Libya (1.87 mbd) and the United Kingdom (1.58 mbd). The numbers in parentheses are the production numbers cited by the EIA for 2008. To further put these countries in context, these take us down to number 18 on the list, and with one more post I will have covered all the countries that produced more than 1 mbd on average in 2008.

I will start with Nigeria, which now is cited as producing 2.4 mbd of crude and condensate in January 2011. The country has been having considerable trouble with sabotage and internal unrest, which has had a negative impact on production. However the country signed an Amnesty Program with militants in 2009 which has reduced disruption. As a result in February Nigeria was able to raise production to 2.6 mbd. If this can be sustained it will bring production back over the peak level that was achieved back in 2005.


Note that, for crude oil production alone, Nigeria is listed as producing 2.17 mbd in January, according to the February OPEC MOMR. (Which is also a gain from the above chart). In light of some of my recent comments on who might be hurt if oil production in some of the MENA countries drops off, it is perhaps interesting to note which countries got oil from Nigeria in 2009.

Nigerian oil customers in 2009 (Source EIA )

Historically Nigeria flared much of the gas that was associated with the oil, particularly in the Niger River Delta, where much of the oil is found. That practice led to some of the more dramatic stories that came from the region, before the amnesty. There is, however, a concerted effort now to capture and market this natural gas, as well as that which comes from gas wells in the country. This has led to some optimism by the Government over future sources of revenue.

The Minister also disclosed that the establishment of two new Liquefied Natural Gas, LNG plants, in Olokola in Ogun/Ondo States and Brass LNG in Bayelsa state, will create over 7,000 jobs and inject over $1billion into the host communities.

There are a total of 6 LNG trains at Finima, on Bonny Island, first coming into production in September 1999, and supplying a variety of customers. While the capacity is at 1.1 Tcf, recent figures have been at about half that volume. (And this is about the same volume that continues to be flared in the country.)

With Nigeria having increased overall production since 2008, though potentially having limited potential for much greater increase, the next country down the list is Angola which, since 2007, is also in OPEC, and OPEC list the January Angolan production of crude at 1.62 mbd. This is significantly below the overall 3.8 mbdoe that BP has reported for total energy production in 2010. Because of some technical problems with water injection, being used to help move oil from the reservoirs, moves to address the problem might overall, reduce the average for 2011 to 3.4 mbdoe. Angola exports about 1. 7 mbd of oil, but is responsive to OPEC requests to control production in order to keep prices at the OPEC comfort level. (Which has risen from around $75 to over $100/bbl in the last few months). Thus the declines shown in the EIA plot below, which only shows through 2009, are more politically induced than due to geological conditions. The EIA, for example, lists project for this year alone that are expected to add 650 kbd to production, and likely export. Unfortunately we are now far enough down the list that while these numbers are significant in their own right, and for the country they may not give that much help to the overall shortages that may evolve over the next year.


Angola currently is building an LNG project at Soyo, expected on stream in 2012 which will handle around 1 bcf/day. Apart from the LNG, which will be exported, the plant will send some 125 mcf/day of natural gas into a distribution network for domestic consumption. Until the plant comes on line most of the almost 1 bcf of natural gas that is produced every day is either flared or reinjected to help with oil production.

Trying to project Libyan future production is rapidly becoming meaningless, I fear as the initial moves to remove the current Leader have not met with sufficient success to eliminate the possibility of civil war. It was only a few weeks ago that Libya was producing at around 1.6 mbd of oil, and Luis de Sousa has reposted an earlier review of the past history of their production. He presciently notes in that post that the rising population of the country is going to demand more of the resource be spent at home. The topic of Libyan production will likely continue to appear in other posts – as it just has – but at the moment it appears, for a variety of reasons, that the system is effectively shut down.

Little if any oil can be shipped out of Libya because most ports were closed. Meanwhile, storage tanks were filling up rapidly. Oil traders said one major oil company cargo ship was supposed to berth this week, but no one was at the port to deliver an oil shipment, and shipping companies were reluctant to send ships into the Libyan ports.

I have also discussed elsewhere the likelihood of sufficient increase in production in other countries to make up the shortfall. Gazprom has been helping Italy, for example, and Saudi Arabia increasing production, but how long this will last, and how much will ultimately be needed remains an unknown. It really depends on how many dominoes fall, and how long they remain on the table.

Which brings us to the United Kingdom. Back in the troubled days of the first oil shocks some thirty to forty years ago, it was the combination of new production from the fields in the North Sea and the North Slope that helped bring oil prices down to the low level which allowed the years of growth until now. But we have reached a point where those resources are beginning to disappear, and the UK has turned from an energy exporter to a growing importer. Euan Mearns has documented this progression in a much more detailed and better way than I illuminating, for example, back in 2008, the coming seriousness of their problem.

Euan’s plot of the UK Predicament, from 2008

If we look at the situation today, the reports for last year note

In 2010, the UK produced 850 million barrels of oil and gas equivalent (boe) or 2.3 million boe per day. Current plans now target reserves of 11.6 billion boe, 1.3 billion boe more than was anticipated a year ago, reflecting the outcome of increased exploration and appraisal activity across the UKCS and particularly West of Shetland. Oil & Gas UK believes there could be up to 24 billion barrels of oil and gas still to recover from the UKCS.

This was about 60% of the UK energy need. Production of crude for last November was 1.047 mbd from offshore, and 9,344 bbl from land wells. The natural gas numbers were 2.7 Bcf from offshore oil wells (as associated gas) and 2.8 Bcf from offshore gas wells. In addition there was some 12 kbd of condensate from the offshore gas fields.

Whether one uses Euan’s plot, or that from the Energy Export Databrowser:

UK Oil statistics (Energy Export Databrowser)

The UK is clearly entering a more expensive future as it must find more oil from overseas, just as that supply is tightening.

On the other hand, while the situation is getting somewhat worse more rapidly with natural gas, as the EIA plot below shows ( and it contributes to Euan’s total figures) there is a sufficient glut on the world market at the moment that there will not be that immediate a problem in the short-term.

United Kingdom trends in gas statistics (EIA )

UPDATE The energy situation in the UK is becoming recognizably more dire, and the Secretary of Climate and Energy, Chris Huhne has just pointed out that the price of $100 a barrel for oil justifies a greater investment in green technology

Drawing on research conducted for the previous government by Lord Stern, Huhne argued that a $100 a barrel price is the exact point at which the economics of climate change pivot so that it becomes cheaper for British consumers and businesses to invest in green technology than remain with the status quo.

He said that if oil only reaches $108 a barrel by 2020 as predicted by the US Department of Energy, which would also lead to higher gas prices, then "the UK consumer will win hands down". He said the UK consumer would be "paying less through low-carbon policies than they would pay for fossil fuel policies".

This does not recognize that most renewable energy technology currently focuses on generating electricity, while the crisis is in liquid fuels for transportation, and it also ignores the likely over supply of natural gas which is separate that price from the rising price of oil over the coming years. Tsk!

The current situation in the MENA countries is in such a state of flux, and the impacts barely recognized as yet, that it is becoming even more difficult to have any confidence that the predictions of performance that were being used only a couple of months ago will continue to have much validity in predicting what is likely to occur even in the relatively short term future.

The BP Energy Outlook to 2030 - a review

There is a significant reliance, among those who write on fossil fuels, on the statistics that BP annually compile on global energy production. For example it provides underlying information for Energy Export Databrowser, as well as many of the posts at The Oil Drum. And so when BP just released their forecast for Energy for the next 20 years (Energy Outlook 2030) it is worth having a look at to see what they predict. Bear in mind that this is only one company prediction, yet nevertheless it is an influential one.

The report is very briefly summarized in the introductory speech by Bob Dudley, the Chief Executive, who chose the following highlights:
• Global energy growth will average 1.7%, but will be generated by non-OECD nations, while demand from OECD will remain relatively stable.
• Oil supply will grow at around 1% per year, with major increases in supply coming from OPEC, particularly Saudi Arabia and Iraq.
• Coal use will grow at an average of 1.2% per year, largely through demand for power from non-OECD nations.
• Natural gas will be increasingly used as a power source, with demand growing at 2.1% per year.
• Renewable energy sources will continue to be favored, with growth being at around 8% per year, and with demand for biofuel tripling over the two decades.
• Deeepwater production of oil will rise from 7% of the global demand to 9% by 2020.

Those were the initial highlights, and there is slightly more detailed summary at the BP website. Since the booklet that summarizes the data is some 30 pages long, but uses a considerable number of graphics to show the projections, let me borrow some of these to summarize what I see as some of the critical points (and I will add a few editorial comments as I go).

The review (which is the first of its type that BP has released) recognizes that the face of energy consumption is changing. As the world population continues to grow, the shift in energy intensive industries to the developing countries has shifted the locations where demand will grow. Since industrialization also increases the energy use by their populations, there is a compounding rise in their energy use.

Projections of population and Energy Growth (BP Energy Outlook)

What is more interesting to me is how they see how this energy will be supplied. The overall projection is shown in this chart:

Projected future source of Energy Supplies (BP Energy Outlook)

The fastest growing of these segments is that of renewables (which includes biofuels). This can be seen more explicitly in this graph from the report:

Sources of Future Energy Supply (BP Energy Outlook)

The growing impact of renewable energy production will affect both electricity generation, and transportation (the latter mainly through biofuel growth).

Looking specifically at the different fuel sources, the report anticipates that oil growth, will be some 16.5 mbd over 20 years, but that this will have to also compensate for about 4.5 mbd of declines in non-OPEC producers. Non-OPEC will, however, see an increase in overall production, the gains coming from about 2 mbd of increased production from oil sands (with the assumption that this is Canadian, since it is not credited to OPEC, of which Venezuela is a member), from the FSU, and from a significant increase in biofuels, only some of which is anticipated to come from the sugar-based ethanol of Brazil.

Sources of future liquid fuel supply (BP Energy Outlook)

In looking at the above chart it is important to recognize the distinction between the FSU and Russia itself, since that country may well start into a decline in production within the year. The increased production will come from places such as Azerbaijan and Kazakhstan.

The second point is that relating to biofuels, where BP note that renewables currently provide 3% of liquid fuel for transport, but that this is expected to rise to 9%. (Within the next 20 years increased rail, electric, hybrid and CNG are not expected to make a material contribution, though CNG use is expected to be about 2%). The concern with biofuel production is that it is virtually all anticipated to come from ethanol. And, as we have just seen with the closure of the Range Fuels plant in Georgia this week, the commercial viability of cellulosic ethanol has yet to be established, challenging not only the BP view of the future, but also that of others. The practicality of further increase in corn ethanol production in the United States is doubtful, giving the rising cost of the raw feed stock (corn). However this is the projection, and increasingly BP expects that biofuels will meet increases in liquid fuel demand (rising to meeting 60% of the growth by 2030). There is, however, an allocation of 1 mbd for increases in refinery gains (which I have discussed earlier) and from natural gas and coal, which perhaps gives some indication of their opinion of this latter effort.

Anticipated size and source of Biofuel production (BP Energy Outlook)

It is the dramatic increase in transport demand, particularly in Asia, that will drive the increased demand for liquids, China alone is expected to pass the United States in oil consumption within this time frame. To further supply that growth, NGL increases of more than 4 mbd from OPEC, and crude oil production growth mainly from Saudi Arabia and Iraq is projected. (In this regard it should be noted that a year ago BP were anticipating that Iraq might be producing 10 mbd by 2020 – the current more realistic target is 5.5 mbd by 2030. And while Iraq has stated it may be able to reach 12.5 mbd by 2017, the condition of the infrastructure in the country, among other issues, would suggest that BP are now more likely correct). Whether Saudi Arabia will rise to the challenge of producing (and likely more critically exporting) at the levels BP projects, given the current age and production history of its main fields is a question, since recent pronouncements from that country suggest a more conservative production capacity of 12 mbd and a disinclination, perhaps, to produce at even that level. (BP assume that both Russia and Saudi Arabia will retain their market share of 12% over the two decades, which, with an assumed total of over 102 mbd would give them each an assumed production of over 12 mbd). To reach the Saudi target BP expect them to expand production capability after 2020.

The major change in fuel use over the next two decades is expected to come in the increasing move from coal to natural gas as the primary source for electricity generation. Because of overall increases in power demand absolute demand for both fuels will increase, but increasingly the demand will shift to NG.

Thus, for example, Chinese growth in demand will rise at 7.6% pa to 43 bcf/day, though this will still only be 9% of their total energy consumption. It is the BRIC countries, which include Brazil, Russia, India and China (and now South Africa) (H/t KLR) whose overall growth in demand, with that in the Middle East, will likely prove greatest over the next two decades.

Expected growth in NG demand in the next 20 years (BP Energy Outlook)

By 2030 BP project that most use of oil for power generation has been displaced, with coal and NG being the primary fossil sources. NG use will increase to about 40% of the market, outside of Europe, where it rises to 65%, given the European concern over climate change. However, in terms of the absolute market, Europe will see a much greater impact from renewable resources generating power, so that the percentage that NG provides will only rise to 24%. Over half the NG supply in North America will come from shale gas and coal bed methane (CBM), elsewhere the impact from those resources will, within this time frame, be much less. Whether or not these unconventional resources reach the 57% market supply by 2030 will likely depend on the development of at least one new technological breakthrough that lowers cost while increasing long-term yield from the wells, but that is a quite feasible assumption.

Electric Power generation by source (BP Energy Outlook)

The market for LNG is anticipated to grow significantly (4.4% pa), particularly in Europe and Asia. Supply is initially seen as coming from the Middle East, but this will be followed by production from Australia which will overtake Qatar by 2020, and then African deposits will come on line providing 41% of the supply by 2030. It is interesting to note the caveat that BP introduce into this projection.

We assume that policy supports the continued rapid growth of non- fossil power generation – especially renewables, which attain a global share of 10% by 2030. Where gas is available at a competitive price, it continues to displace coal.

Regional demand growth for LNG (BP Energy Outlook)

It is the response that China makes in changing their primary source of power as they continue to expand production, and thus energy demand, that will decide how far, and how fast the transition from coal will occur. BP anticipate that the market overall will continue to rise until just before 2030, at which time it will flatten. But whether that happens will likely depend on availability and price, of both coal, and its potential replacements. (Hence the caveat).

BP recognize that this is only a base case projection, and that there are many different factors that will likely change the final results. That is likely to be particularly true if there is an upsurge in interest in climate change legislation and regulation. I have made some comments on how accurately I think that the models have been developed, but that should not detract from the value of this particular document which, being freely downloadable, is well worth getting and saving.

Afghan oil, and gold, and iron

I noted today that the Afghan government is beginning to pin some hopes on oilfield development as a way of helping generate some desperately needed cash. It was just last August that a field containing up to 1.8 billion barrels of oil was reported. There has been exploration and hopes of significant production in Afghanistan since 1937 but there has been little significant production as yet. Prior to the Soviet invasion in 1979 it had been estimated that the country had 100 million barrels of oil and a refinery was planned, but cancelled by the resulting conflict. The Angot field had been identified, and some 14 wells drilled into it, without much production. In those years much of the Afghan energy production was in natural gas, that was shipped to the Soviet gas grid, via Uzbekistan. The conflict and guerrilla activity in the region lowered production, and when the Soviets left many of the wells were capped.

An attempt to start the oil production process over at the beginning of this year was not successful, with only a single, rejected, bid being received. A Norwegian evaluation of the situation in June suggested that it was too early for a decision.

Balancing the notable achievements that have come in place through Norwegian facilitation and support for the Government of Afghanistan with the range of risks identified in this report, and not least the two central conflict issues identified in the literature review, Norad is advised to consider the following: Await further engagement on policy matters relating to implementation of the Hydrocarbons Law and a new (if materializing) Hydrocarbons bidding round until there is further clarity as to how the Government of Afghanistan aims to develop and utilize these resources and to what extent major external donors support such policies”.

But by August, when the new discovery was made, a rig had been fielded in the Angot field in the Sar-i-Pol (Sar-e-Pul) region in the North to begin a production stream. It is that field that is now being brought on line, looking to production from both new wells and some of the existing older ones that will be refurbished. Production will only be on the order of 800 bbl/day but for a country where the United States spends $250 million a year providing diesel for the Afghan forces, any start is welcome. The oil will be extracted by the Afghan government and then sold at $80 a barrel, and is being marketed to an Afghan group, Ghazanfar Group. The company is one of the largest private companies in the country, and made $475 million in gross earnings from its petroleum business in 2008 (up from $2 million when it got into that business in 1998).

And just as the “black gold” of the country is starting to be developed, so also is the real yellow stuff. Plans were also announced for a gold mine to be opened.

About 10 investors - most of them from the United States and Britain - are investing an estimated $50 million in the gold project in Dushi district of Baghlan province, about 84 miles (135 kilometers) northwest of Kabul, Wahidullah Shahrani, Afghanistan's minister of mines, told the Associated Press. The only other gold mine in Afghanistan is in neighboring Takhar province.

There has been considerable talk of the mineral wealth that is part of the Afghan geology. These developments, and preliminary discussions on the mining of the largest iron ore deposit in Asia, that at Hajigak, reputed to have 1.8 billion tons of a 62% purity, are an indication that there can be progress in moving the country into a more prosperous future.

It is interesting to note, however, that in the case of the iron, as is the case with some of the oil in Iraq, it is China and India that are looking to develop the industries, and thereafter likely to consume the product. It Iraq they are already hard at work. The Chinese are willing to go into countries such as Iraq, and Afghanistan, as well as Sudan, which now sends more than 60% of its oil output to China. They face the difficulties of operating in countries under wartime conditions, and yet the benefits that can accrue will assure them of needed supplies in the years ahead.

The new fields that are being developed in Afghanistan lie in the north of country and the oil transitions to gas as the reservoirs approach the Turkmenistan border and the much richer gas deposits that lies north of the Amu Darya River. The new developments are also to the East of the planned route for the gas and oil pipelines that have been discussed, for many years, as a way of bringing needed energy to India and Pakistan.

Planned Afghan pipeline ( derived from one in The Canadian )

And while the pipeline may remain more a paper exercise, the production of the fuels has begun. But it should not be forgotten that the Chinese have already initiated one pipeline with Turkmenistan and that pipeline is a whole lot closer to these fields, over less disputed ground, than it would be sending the production South.

Saudi Oil Production - read Minister Al-Naimi's small print

Yesterday the Saudi Arabian oil Minister, Ali Al-Naimi, commented that the days of easy oil are not over, and that there remain at least 88 billion barrels in the Saudi oilfield of Ghawar, let alone the rest of the fields in that country. Well before that sends you out to buy a fleet of Hummers, you might want to take a wee bit closer look at some of the other things that he said, or did not say. For the future is not quite as rosy as his remarks might, at first, make you think.

Let’s start with the “days of easy oil are not over.” That is a somewhat egregious remark. It is relatively easy for the Kingdom of Saudi Arabia (KSA) to brag that it is still not that expensive to produce oil. Given the size and extensive development of their fields that is, at present, still to a large extend true for them. But Aramco have carried out extensive research into modeling their fields and developing technologies such as maximum reservoir contact (MRC) on order to get the maximum amount of oil out of their fields. (And I’ll get around to that in a minute). But the KSA only produce a fraction of the increasing amount of oil that the world needs every day. And it is the cost of the oil at the margin (that which balances oil supply with need) that to a much greater degree controls the price.

At the moment the countries that make up OPEC can increase production at need, beyond the current levels of demand. As long as they can do this they can impose controls on the price. This is because the rest of the world is producing just about as fast as it can and there is some doubt, despite some rosy predictions, that they will be able to raise levels above those currently produced. If the price falls too much, then some of the more marginal oil, that is more expensive to produce, might drop off the market. At that point, if OPEC cannot make up the difference, and I would argue that beyond a certain relatively low volume (4 mbd) it no longer can, then prices will rise again. There is an effective lower bound on price now, significantly higher than OPEC costs.

Last week at the ASPO-USA Conference Michael Klare commented on the amount of money that this will bring to the nations that produce oil much cheaper than the global price (which KSA is happy to keep at around $80 bbl) but to keep that price it relies on the make-up oil that is not “easy” at all. This includes oil sand and deepwater production.

Now let me turn to some of the more worrisome part of what he said. Until recently it has been assumed that KSA was going to raise production to levels of 12.5 mbd as part of the balancing act to match declines in other fields and meet supply. (And some time before that there was talk of Saudi production levels of up to 15 mbd). However the KSA has a problem. To get the maximum recovery from their fields they have to control the interface between the waterflood and the oil., and move it relatively slowly and evenly through the reservoir. They are quite good at this, and likely getting better. But it means that they produce the oil at, for them, relatively slow rates. And they are slowing these down a bit. As a result the maximum that they are now talking about is 12 mbd. Which means if you are looking at the global balance over the next few years you have just had to take an eraser and remove 500,000 bd from the available supply. Note that this is not quite 50% more than current production.

Why is this? Well that comes to another part of the remarks that the Oil Minister made. The next major plan for production of oil is the development of the Manifa oilfield. It was, at one time, scheduled to produce a million bd, but this is now dropped to 900,000 bd. But there is a greater concern.

Manifa is a heavy, sour (i.e. high sulfur), vanadium contaminated deposit. It requires a special refinery to process the oil, and these don’t exist. The KSA has had plans in the works for some time to build two refineries in the Kingdom that will refine this oil. There have, however, been delays in construction. It appears that these are getting worse, or, for other reasons, have been further postponed. Without the refineries the ability to produce the oil is meaningless. The original date at which these facilities were supposed to be on line was within the next two. It is now, apparently, been moved to 2024. Presuming that this is not a misprint (since the last target was 2013) it means that KSA has changed its strategy and is not looking to ever produce above the 12 mbd current target as we move into the future.

Naimi said the kingdom has sufficient production capacity at 12 million barrels per day (bpd) and has a strategy of preserving its resources and developing new sources of energy.

"We have the production capacity and we don't have to deplete our reservoirs as fast as someone who's just there for investment...so we don't really have to pull our reservoirs as hard as we should," Naimi said.

With their internal consumption continuing to rise, and with increasing sales to China, the amount of that oil which is going to be available to the West is going to go down.

Whether and when they will get to 12 mbd now becomes more of a question. Given current levels, and the income that they are getting from them, it is hard for me to see production rising to even 11 mbd. (subtracting the volume from Manifa). And if world consumption is rising at around 1.5 mbd per year, for the sake of discussion, then we are going to see an imbalance between production and supply needs, in just about 2 years.

Given that this was the message from the ASPO_USA conference, it is interesting to see the Saudi Oil Minister so rapidly confirm it.

So I’m afraid the difference between the headline of his remarks and the small print of his text are enough apart to be disturbing.

And I must apologize in that this was written on the train from Vienna to Graz and I don't have access to all my usual references, which I would insert.