It is difficult to see any positive interpretation of the changes and conflicts that are increasingly filling the headlines of the press. Fluctuating optimism over the return to credible export production from Libya, to take but one example, is no sooner reported when the news comes of increased fighting in Tripoli, including the international airport. At the same time violence is spreading towards Egypt. Without a strong central government it is likely that the conflicts in that country will continue into the foreseeable future, with continued negative impacts on the export of oil from the country.
Transient attempts to maintain a cease-fire and stabilize South Sudan have apparently failed again. The fighting has shut down local oil production, while overall production from South Sudan has been cut to 165 kbd.
Capital continues to leave Russia (h/t Nick) and that flight is only likely to accelerate as the tensions over the shooting down of the Malaysia Airlines plane continue to grow. Given that investment continues to be required to sustain Russian oil production against the current transition into decline, and that such cash is not being spent only magnifies the concern that Russian export decline will be faster and sooner than the world anticipates. (And given the critical value of Russian oil and gas exports to their economy – it provides about half the budget revenue - President Putin desperately needs a scapegoat to blame as the economic gains of the past, and future growth targets of over 5% become unrealistic dreams for that future).
With the emphasis on the daily events in all these countries (not forgetting Iraq) it is more difficult to discern the overall medium term impact that this is likely to have on oil availability, and consequently on oil and gas prices. Europe cannot function at current economic levels without the 30% of its energy that it gets from Russian natural gas, which has to be a big consideration as they discuss whether to impose more sanctions on Russia. While a recent Total study shows that, with Gazprom co-operation, Europe could cope if flows through Ukraine were stopped, without that co-operation the EU would not be able to adequately replace the lost fuel. And the conflict in Ukraine is unlikely to be resolved fairly soon, so the degree of co-operation that Western Europe can expect from Gazprom next winter is likely to lead to some fairly tense negotiations over the next few months.
One of the frustrations with watching TV pundits muse on this is that there seems to be an assumption that wells, pipelines and other necessary infrastructure will magically appear to provide immediate solutions should things start to get worse. One such today commented that President Putin is now in total control, since should the west decide not to take all of the Russian oil and natural gas that they currently consume, that he could immediately increase sales to China to replace the lost income.
That neglects the time that it is going to take to get the wells drilled in Siberia, the pipeline connections made and the receiving network in place to meet the current amount that has been sold. Even with the current agreement to increase Russian exports to China it is going to take some four years for the new gas to flow, and it took years for this agreement to be signed.
By the same token Europe can’t turn around and expect the US to be able to replace any significant amount of Russian natural gas for about a similar period of time. Facilities cannot be created overnight, and permitting and construction take finite amounts of time.
I would expect that, if anything, the price that is charged for Russian oil and gas is going to go up for the Europeans, even as the oil supply starts to decline. As Euan Mearns has noted all the significant producers of natural gas in Western Europe are seeing declines in production and while the fall last year was not that significant, overall the continued cumulative decline will make the need for Russian gas that more critical, given that the pipelines are in place to deliver it.
Unfortunately as oil and natural gas supplies continue to tighten, the natural consequence is going to be an increase in price. And this will, in turn, affect the economic growth of the different countries around the world. The current price has slowed economic growth, but as it continues to ratchet up then the impact on global growth will become rapidly obvious, although differentiated by country depending on how dependent they are on fuel imports.
Complacency within the United States, given the assumptions of indigenous supply availabilities, is likely to be shaken as internal oil supplies stop there unsustainable growth rates, while the current low prices for natural gas will disappear as the available funds for future wells reduce on the increasing evidence that most of these wells are unprofitable at current gas prices.
It is difficult – well, to be honest, impossible - for most of us to be able to see how almost any of the growing conflicts around the world can be resolved in any short-term period. The consequent impact on oil production in the countries of the Middle East and North Africa (MENA) is going to lead to a tightening of the surplus between available supply and demand, particularly at current levels. And, unfortunately, when economic circumstances grow colder political rhetoric gets hotter, and there is less chance for negotiation and diplomacy to resolve the situation.
The main surprise, at the moment, is how rapidly the situation is deteriorating in so many of the countries that supply oil and gas to the world. Sadly the headlines will only cover one or two of these at a time. As a result the overall trends are missed as headlines instead focus on the very small changes driven more by sentiment and political perspective than by the realities of the medium, and even short-term oil and gas supply situation.
Showing posts with label natural gas pipelines. Show all posts
Showing posts with label natural gas pipelines. Show all posts
Sunday, July 20, 2014
Sunday, September 11, 2011
OGPSS - pipelines from the North
Art Berman commented, in regard to my last post on the oil and gas reserves offshore Alaska, that at one time companies looked for an estimated 1 billion barrels in reserves, before they would consider starting down the long road to bringing them to market. With the rising price of oil, that number may have declined a little, but for natural gas a similar need for a long-term assured market is currently potentially raising barriers to progress. As I mentioned in that post, there is a considerable sum involved, not just in acquiring the leases for the sites, but in all the preparatory work needed before the first drill even hits the surface. But even after the wells have come in, the hydrocarbons must still be moved down to the customer, and as the Trans-Alaska Pipeline System (TAPS) showed, it takes time, money and a considerable commitment before that connection can be made.
One of the recent changes that I noted a couple of posts ago, is that more of the reserve in the North Slope is now known to be natural gas, rather than oil. With the current relative natural gas glut in the contiguous United States, that reduces the immediate market, and the potential current price that the gas could bring in. This, in turn, slows lease development. But times change, and with an increase in natural gas demand there will be a growing demand with time. One can also see an increased future need for natural gas in Alberta, where it helps in the production of the heavy oils from the shallow sands around Fort McMurray. And that brings us to the current controversy over the building of another pipeline, this time for natural gas, down from the Arctic.
Possible TransCanada gas pipeline routes from the North Slope, showing connecting pipeline networks, both for it and the MacKenzie River pipeline. (TransCanada)
More particularly I thought I would tie in the problems that the MacKenzie Valley Pipeline has had in Canada, with the debate about the Alaskan pipeline. This is not so much to argue either side, but rather, in showing some of the delays that have arisen, to underscore one of the points that these last few posts have been hopefully suggesting. This is that when somebody says that all we have to do is go out there and drill to solve our energy problems, they really don’t understand the complexities of the real world. The MacKenzie River flows into the Beaufort Sea just to the East of Alaska, in the Canadian Northwest Territories.
Proposed path for the MacKenzie River Pipeline
The recent application for approval of the MacKenzie River pipeline was originally filed in August 2004. But by then the project was already old. Back in 1977 Mr. Justice Berger (a Canadian Judge) who had examined the project over a three-year period, recommended that it be put in abeyance for 10 years, following his Inquiry. A major concern of the time was the expressed opposition of many of the native tribes (First Nations) through whose land the pipeline would run.
Move forward some 34 years, and some of those tribal leaders are now in favor of the project. And while, in that time frame, the Canadian Government had pledged billions to the First Nations of Canada, with recent emphasis being on schools, water and community services, a more likely reason is because of the work of settling land claims, (all the land belongs to the First Nations) and, for example, that the Inuvialuit now own the company that runs the barges up and down the river. At the same time, through the Aboriginal Pipeline Group, the First Nations will now also own a third of the pipeline itself.
At the time that the National Energy Board approved the project it included the development of three natural gas fields (Niglintgak, Taglu and Parsons Lake), about 120 miles of gathering pipelines and an almost 300-mile natural gas liquids pipeline as well as the 743-mile pipeline itself, which will carry 1.2 Bcf/day of gas down to Alberta.
With construction now scheduled to begin in 2014, (and to occur mainly during the winter months) it is expected that the pipeline will be in operation by the end of 2018, at a cost of $16 billion. It will take some $800 million to develop the Niglintgak field with 6 - 12 wells started from 3 pads. It will take some $2.5 billion to develop the Taglu field, with 15 producing wells extended from a single pad, but requiring a compressor and more wells as the field ages. And the cost of the Parsons Lake field is anticipated to be around $2,5 billion with two drilling pads that will hold from three to nineteen wells.
Now move West a tad, and Alaska also has those significant gas resources that I have mentioned in previous posts. They are, however, not quite as far along in the process of getting a pipeline in place to move it to where it becomes a real reserve. I will forego exploring the idea (mentioned in comments on earlier posts) of converting the natural gas to methanol and sending it down TAPS to Valdez, where it would be separated from the oil, and converted into gasoline. (Although, because methanol is corrosive to pipes, the plan is moving toward doing the conversion to gasoline near Deadhorse, and mixing the gasoline with the crude.) The initial target for the project would produce 63 kbd of gasoline, with an original estimate of the cost being around $7.7 billion.
Moving the natural gas itself through a new pipeline, however, requires customers, and while a number of different proposals have been put forward, the lack of such customers at this time recently caused Denali to discontinue their efforts to build a 48-inch diameter pipe that would carry up to 4.5 Bcf/day from the North Slope to Alberta.
Path of the proposed Denali Natural gas line from the North Slope. (Denali )
TransCanada, who remain in the hunt, is also finding it hard to find any firm customers. Given that they estimate that the cost of a similar sized pipeline would run between $20 and $41 billion, depending on whether the line feeds an LNG plant in Valdez, or runs over into Alberta, they are hesitant to move forward, even though they will receive $500 million for planning the project, and getting the regulatory approvals. (The top map shows both alternatives)
The TransCanada/ExxonMobil option to Valdez. (Alaska Pipeline Project)
Nevertheless TransCanada and Exxon, who are now partnering in the Alaska Pipeline Project have held meetings with the project communities likely to be affected by the project, offering refreshments and door prizes for the present and potential feeder lines in the future. Their presentation can be found here, and notes that under the current schedule first gas will flow in 2021.
By that time it is quite likely that there will be more of a demand for natural gas supplies in the anticipated market, but convincing investors and potential customers of that is likely to be an uphill task in the more immediate term, and the project will likely not be able to make headway until those folk show up. And so, while it may not take the almost 40-years of the MacKenzie River pipeline (which isn’t started yet) the current Alaskan effort is likely to take longer than currently hoped.
One of the recent changes that I noted a couple of posts ago, is that more of the reserve in the North Slope is now known to be natural gas, rather than oil. With the current relative natural gas glut in the contiguous United States, that reduces the immediate market, and the potential current price that the gas could bring in. This, in turn, slows lease development. But times change, and with an increase in natural gas demand there will be a growing demand with time. One can also see an increased future need for natural gas in Alberta, where it helps in the production of the heavy oils from the shallow sands around Fort McMurray. And that brings us to the current controversy over the building of another pipeline, this time for natural gas, down from the Arctic.
Possible TransCanada gas pipeline routes from the North Slope, showing connecting pipeline networks, both for it and the MacKenzie River pipeline. (TransCanada)More particularly I thought I would tie in the problems that the MacKenzie Valley Pipeline has had in Canada, with the debate about the Alaskan pipeline. This is not so much to argue either side, but rather, in showing some of the delays that have arisen, to underscore one of the points that these last few posts have been hopefully suggesting. This is that when somebody says that all we have to do is go out there and drill to solve our energy problems, they really don’t understand the complexities of the real world. The MacKenzie River flows into the Beaufort Sea just to the East of Alaska, in the Canadian Northwest Territories.
Proposed path for the MacKenzie River Pipeline The recent application for approval of the MacKenzie River pipeline was originally filed in August 2004. But by then the project was already old. Back in 1977 Mr. Justice Berger (a Canadian Judge) who had examined the project over a three-year period, recommended that it be put in abeyance for 10 years, following his Inquiry. A major concern of the time was the expressed opposition of many of the native tribes (First Nations) through whose land the pipeline would run.
Move forward some 34 years, and some of those tribal leaders are now in favor of the project. And while, in that time frame, the Canadian Government had pledged billions to the First Nations of Canada, with recent emphasis being on schools, water and community services, a more likely reason is because of the work of settling land claims, (all the land belongs to the First Nations) and, for example, that the Inuvialuit now own the company that runs the barges up and down the river. At the same time, through the Aboriginal Pipeline Group, the First Nations will now also own a third of the pipeline itself.
At the time that the National Energy Board approved the project it included the development of three natural gas fields (Niglintgak, Taglu and Parsons Lake), about 120 miles of gathering pipelines and an almost 300-mile natural gas liquids pipeline as well as the 743-mile pipeline itself, which will carry 1.2 Bcf/day of gas down to Alberta.
With construction now scheduled to begin in 2014, (and to occur mainly during the winter months) it is expected that the pipeline will be in operation by the end of 2018, at a cost of $16 billion. It will take some $800 million to develop the Niglintgak field with 6 - 12 wells started from 3 pads. It will take some $2.5 billion to develop the Taglu field, with 15 producing wells extended from a single pad, but requiring a compressor and more wells as the field ages. And the cost of the Parsons Lake field is anticipated to be around $2,5 billion with two drilling pads that will hold from three to nineteen wells.
Now move West a tad, and Alaska also has those significant gas resources that I have mentioned in previous posts. They are, however, not quite as far along in the process of getting a pipeline in place to move it to where it becomes a real reserve. I will forego exploring the idea (mentioned in comments on earlier posts) of converting the natural gas to methanol and sending it down TAPS to Valdez, where it would be separated from the oil, and converted into gasoline. (Although, because methanol is corrosive to pipes, the plan is moving toward doing the conversion to gasoline near Deadhorse, and mixing the gasoline with the crude.) The initial target for the project would produce 63 kbd of gasoline, with an original estimate of the cost being around $7.7 billion.
Moving the natural gas itself through a new pipeline, however, requires customers, and while a number of different proposals have been put forward, the lack of such customers at this time recently caused Denali to discontinue their efforts to build a 48-inch diameter pipe that would carry up to 4.5 Bcf/day from the North Slope to Alberta.
Path of the proposed Denali Natural gas line from the North Slope. (Denali ) TransCanada, who remain in the hunt, is also finding it hard to find any firm customers. Given that they estimate that the cost of a similar sized pipeline would run between $20 and $41 billion, depending on whether the line feeds an LNG plant in Valdez, or runs over into Alberta, they are hesitant to move forward, even though they will receive $500 million for planning the project, and getting the regulatory approvals. (The top map shows both alternatives)
The TransCanada/ExxonMobil option to Valdez. (Alaska Pipeline Project)Nevertheless TransCanada and Exxon, who are now partnering in the Alaska Pipeline Project have held meetings with the project communities likely to be affected by the project, offering refreshments and door prizes for the present and potential feeder lines in the future. Their presentation can be found here, and notes that under the current schedule first gas will flow in 2021.
By that time it is quite likely that there will be more of a demand for natural gas supplies in the anticipated market, but convincing investors and potential customers of that is likely to be an uphill task in the more immediate term, and the project will likely not be able to make headway until those folk show up. And so, while it may not take the almost 40-years of the MacKenzie River pipeline (which isn’t started yet) the current Alaskan effort is likely to take longer than currently hoped.
Read more!
Sunday, February 20, 2011
OGPSS - Lower second tier oil producers - Norway, Brazil, Iraq and Algeria
This current series of posts is aimed at an overview of the top oil producing nations, seeking to establish how the ranking of the countries is changing from the original table that EIA put out in 2008, After looking at the conditions governing the top six, this was followed last week when I looked at the condition of the following three (Mexico, UAE and Kuwait) in a little detail, but, having spent four posts on Veneuela in the recent past forebore going back there again.
Source EIA
It is worth recapping, however, that the initial order has changed, and that, currently Russia is at the head of the League, slightly ahead of Saudi Arabia., and both producing somewhere around 10.2 mbd. I’ll go more into that detail as the posts focus in on the individual countries later. The United States production, if one includes ethanol, is around 8.2 mbd, and this is in third place,. China has moved into fourth place, slightly ahead of Iran which is followed by Canada. At present these six appear to be the only countries producing over 3 mbd.
In the next tier down I have already mentioned the United Arab Emirates, which have moved into 7th place, with a production of around 2.81 mbd, how ahead of Mexico, albeit perhaps barely (based on the addition of NGLs etc). As with the UAE Kuwait has been limiting production in line with OPEC requests, but while only producting at around 2.35 mbd at the moment, is looking to increase this to up to 3.5 mdb by 2015, which would move it into the top tier. Venezuela, although it too has some grandiose plans, based on the potential increases in production from their tar sands, is currently producing at down around 2.26 mbd. As I have mentioned Venezuela does have plans to raise production to 4 mbd by 2015. However recent commitments to China of up to 1 mbd and problems that Venezuela continues to have in meeting current obligations leaves a large question mark on those predictions.
And so we come to the lower half of the second tier.
In order to create the current ranking we have to first work out what the current levels of production are, and the future potential. So let’s start with Norway, since that country did rank 11th in 2008. Statoil has noted that their equity liquids production fell to 1.945 mbdoe in the fourth quarter of 2010. Statoil anticipate that there will be little change in production this year, but that there may be a slight rise thereafter. Statoil is not, however, Norway, being responsible for about 80% of the countries production (with properties abroad as well) but I mention it as indicative of the trends. One hopeful sign of which been the agreement with Russia that defines who owns what in the Barents Sea. However when we look at the long-term Norwegian trend is is recognizably downwards, with the Norwegian Petroleum Directorate predicting a 1.7 mbd average production in 2011. The Directorate is predicting that oil production will fall to 1.54 mbd by 2015. This does not consider other liquids and if these are included, while the overall total still lies below 2 mbd, it is currently a lot closer to that, though that is not expected to last.
Norwegian oil production in 2011 (Norwegian Petroleum Directorate)
In January this total, was made up of 1.836 mbd of crude oil, 256 kbd of NGLs and 69 kbd of condensate. Most of Norwegian production is exported, and the percentage can be seen from the EIA Country Analysis. The relatively flat domestic production is (as we have discussed with the Export Land Model) not typical.
Declining production, and thus exports of petroleum from Norway (EIA )
Natural gas production, on the other hand, is continuing to rise, though it depends on finding and developing new fields, and 95% of this is exported.
Norway produced 3.65 Tcf in 2009, with the majority of production coming from the Troll, Oman Lange and Asgard fields.
The next country down the 2008 list was Brazil, and here there is a change in order since Brazil is now rising past 2.12 mbd of crude production in December, moving ahead of Norway. Offshore production in the Tupi field, which may hold 6.5 billion barrels of oil, will be followed by that from the Jupiter field, possibly of similar size. The fields fall deep offshore in the Santos and Campos Basins, which will deserve a couple of posts on their own, down the road.
Location of the Santos and Campos Basins off Brazil
Development has now started.
Brazil plans to double crude production from the current 2 mbd to 4 mbd by 2020, reaching 3 mbd by around 2014. However overall liquids production is already at 2.7 mbd and the EIA anticipates that this will rise over 3 mbd by next year. With the cumulative liquid totals Brazil has also passed Venezuelan production and may soon be competing with Kuwait as they both move into the top tier.
Brazil also produces ethanol, mainly from sugar cane, with production at around 450 kbd However, with a growing economy, the country does not, as yet, have much of its production available for export. (The BP figures are a little more pessimistic than those of the EIA).
Brazilian oil information (Energy Export Databrowser)
Brazil continues to find oil onshore, most recently in the Amazon Basin and this bodes well for the targets that it now envisages.
Brazil gets most of its electric power from hydro-electric power plants, but is able to use the natural gas that is recovered during oil production to meet about half of the national need for gas, the rest being imported.
The next country on the original list was Iraq. And this poses a problem of prediction since we have to decide who to believe in the tales of competing numbers that have been used, among other places by BP in predicting the sources of future oil supply. The problems in this case are as much geo-political and locally ethnic and religious as they have to do with the capabilities of producing oil. At the moment Iraq has finally got back up to a production level of 2.6 mbd not that this will necessarily help Western imports that much:
In January, OPEC reports, Iraq produced a total of 2.7 mbd, which was 300 kbd up on production in the last quarter of 2010. To put this in context in February 2003, just before the conflict began, Iraq was producing 2.8 mbd. At the moment production is centered on the North and South Ramalla fields and that of Kirkuk in the North. The problems of Iraq are not so much, in the short term those of most of the rest of the world, i.e. in finding more oil. In the immediate short term the information on fields that have been known for some time (and in some cases were previously producing) already exists. What is needed is some way of ensuring that the infrastructure is repaired and, if necessary, new pipelines laid. Those plans are now advancing although it is now going to be more difficult to foresee their short-term success, given the developing turmoil in the region. The EIA has posted a table showing the potential from the different regions.
Estimate of oil availability in Iraq
Consumption in Iraq has been fairly stable until about 2007 where it started to climb, and, given a little more stability in the country, it is reasonable to expect that it will surge as it has in much of the Middle East. On the other hand it is a little difficult for me to see production rising to the 12 mbd figures that are now discussed as being possible for Iraq by 2017.
Until recently Iraq was flaring more than 60% of the natural gas that it was producing (perhaps as much as 1 bcf/day) One option that is open is to pipeline some of the gas up to Turkey and then feed it into the Nabucco pipeline. There is a hope that this can lead to exports of up to 2.5 bcf/day but new legal hurdles are continuing to delay progress. Apart from resurrecting the pipelines there is also the possibility of installing an LNG train or two.
And when one is considering the growing instability of the region, the next country down the list is Algeria, and that has now started to be mentioned among the countries feeling the fallout from the initial protests in Tunisia. The Algerian Foreign Minister is denying the risk of a “domino” effect. Possibly this could be because, as it is reported the income from oil and gas sales can, in this case help.
Algeria is a member of OPEC, which reports the January 2011 production of oil at 1.28 mbd, which has been relatively stable for some time. The EIA consider that the crude is some of the finest in the world . Production is supplemented by condensate (450 kbd in 2008) and NGL (357 kbd) for a total liquid fuels production of over 2 mbd. It is the largest oil-liquids producer in the African continent.
Algeria, which operates the oil and gas through the company Sonatrach exports most of its natural gas, through pipelines to Europe and through LNG terminals, with a new one that is to be completed in 2012. Total exports are around 2 TCF making it the fourth largest exporter. (CIA 2011 World Factbook). Gazprom has recently become involved in field development. It also provides a useful fuel for the processing of fertilizer in Morocco, as Jeff Vail noted, back in 2008. As one of the world’s largest exporters of natural gas, Algeria supplies Southern Europe.
Algerian natural gas delivery network
The Algerian reserves are found in the Sahara
But the current turmoil may make some of these plans moot.
Source EIA It is worth recapping, however, that the initial order has changed, and that, currently Russia is at the head of the League, slightly ahead of Saudi Arabia., and both producing somewhere around 10.2 mbd. I’ll go more into that detail as the posts focus in on the individual countries later. The United States production, if one includes ethanol, is around 8.2 mbd, and this is in third place,. China has moved into fourth place, slightly ahead of Iran which is followed by Canada. At present these six appear to be the only countries producing over 3 mbd.
In the next tier down I have already mentioned the United Arab Emirates, which have moved into 7th place, with a production of around 2.81 mbd, how ahead of Mexico, albeit perhaps barely (based on the addition of NGLs etc). As with the UAE Kuwait has been limiting production in line with OPEC requests, but while only producting at around 2.35 mbd at the moment, is looking to increase this to up to 3.5 mdb by 2015, which would move it into the top tier. Venezuela, although it too has some grandiose plans, based on the potential increases in production from their tar sands, is currently producing at down around 2.26 mbd. As I have mentioned Venezuela does have plans to raise production to 4 mbd by 2015. However recent commitments to China of up to 1 mbd and problems that Venezuela continues to have in meeting current obligations leaves a large question mark on those predictions.
And so we come to the lower half of the second tier.
In order to create the current ranking we have to first work out what the current levels of production are, and the future potential. So let’s start with Norway, since that country did rank 11th in 2008. Statoil has noted that their equity liquids production fell to 1.945 mbdoe in the fourth quarter of 2010. Statoil anticipate that there will be little change in production this year, but that there may be a slight rise thereafter. Statoil is not, however, Norway, being responsible for about 80% of the countries production (with properties abroad as well) but I mention it as indicative of the trends. One hopeful sign of which been the agreement with Russia that defines who owns what in the Barents Sea. However when we look at the long-term Norwegian trend is is recognizably downwards, with the Norwegian Petroleum Directorate predicting a 1.7 mbd average production in 2011. The Directorate is predicting that oil production will fall to 1.54 mbd by 2015. This does not consider other liquids and if these are included, while the overall total still lies below 2 mbd, it is currently a lot closer to that, though that is not expected to last.
Norwegian oil production in 2011 (Norwegian Petroleum Directorate) In January this total, was made up of 1.836 mbd of crude oil, 256 kbd of NGLs and 69 kbd of condensate. Most of Norwegian production is exported, and the percentage can be seen from the EIA Country Analysis. The relatively flat domestic production is (as we have discussed with the Export Land Model) not typical.
Declining production, and thus exports of petroleum from Norway (EIA ) Natural gas production, on the other hand, is continuing to rise, though it depends on finding and developing new fields, and 95% of this is exported.
Norway produced 3.65 Tcf in 2009, with the majority of production coming from the Troll, Oman Lange and Asgard fields.
The next country down the 2008 list was Brazil, and here there is a change in order since Brazil is now rising past 2.12 mbd of crude production in December, moving ahead of Norway. Offshore production in the Tupi field, which may hold 6.5 billion barrels of oil, will be followed by that from the Jupiter field, possibly of similar size. The fields fall deep offshore in the Santos and Campos Basins, which will deserve a couple of posts on their own, down the road.
Location of the Santos and Campos Basins off Brazil Development has now started.
The Tupi field is being developed as a pilot project in two phases. In the first phase tests will be conducted to gather information about the future production systems. This phase is expected to end in 2012.
The second phase is expected to start from 2012 and will include two parts. In the first part (2012-17) ten production units will be installed at the field with 20 producing wells and injectors expected to be drilled during this time.
In the second part of phase two (after 2017), new technologies such as dry completion units will be employed to recover oil and natural gas from the field.
Brazil plans to double crude production from the current 2 mbd to 4 mbd by 2020, reaching 3 mbd by around 2014. However overall liquids production is already at 2.7 mbd and the EIA anticipates that this will rise over 3 mbd by next year. With the cumulative liquid totals Brazil has also passed Venezuelan production and may soon be competing with Kuwait as they both move into the top tier.
Brazil also produces ethanol, mainly from sugar cane, with production at around 450 kbd However, with a growing economy, the country does not, as yet, have much of its production available for export. (The BP figures are a little more pessimistic than those of the EIA).
Brazilian oil information (Energy Export Databrowser) Brazil continues to find oil onshore, most recently in the Amazon Basin and this bodes well for the targets that it now envisages.
Brazil gets most of its electric power from hydro-electric power plants, but is able to use the natural gas that is recovered during oil production to meet about half of the national need for gas, the rest being imported.
The next country on the original list was Iraq. And this poses a problem of prediction since we have to decide who to believe in the tales of competing numbers that have been used, among other places by BP in predicting the sources of future oil supply. The problems in this case are as much geo-political and locally ethnic and religious as they have to do with the capabilities of producing oil. At the moment Iraq has finally got back up to a production level of 2.6 mbd not that this will necessarily help Western imports that much:
The rising output will boost Iraq’s oil exports by 5 percent to 2 million barrels a day next month, Falah al-Amri, head of the country’s State Oil Marketing Organization, said today in an interview in Baghdad. The nation sells about 60 percent of supplies to India, China and other Asian countries where demand is increasing, he said
In January, OPEC reports, Iraq produced a total of 2.7 mbd, which was 300 kbd up on production in the last quarter of 2010. To put this in context in February 2003, just before the conflict began, Iraq was producing 2.8 mbd. At the moment production is centered on the North and South Ramalla fields and that of Kirkuk in the North. The problems of Iraq are not so much, in the short term those of most of the rest of the world, i.e. in finding more oil. In the immediate short term the information on fields that have been known for some time (and in some cases were previously producing) already exists. What is needed is some way of ensuring that the infrastructure is repaired and, if necessary, new pipelines laid. Those plans are now advancing although it is now going to be more difficult to foresee their short-term success, given the developing turmoil in the region. The EIA has posted a table showing the potential from the different regions.
Estimate of oil availability in IraqConsumption in Iraq has been fairly stable until about 2007 where it started to climb, and, given a little more stability in the country, it is reasonable to expect that it will surge as it has in much of the Middle East. On the other hand it is a little difficult for me to see production rising to the 12 mbd figures that are now discussed as being possible for Iraq by 2017.
Until recently Iraq was flaring more than 60% of the natural gas that it was producing (perhaps as much as 1 bcf/day) One option that is open is to pipeline some of the gas up to Turkey and then feed it into the Nabucco pipeline. There is a hope that this can lead to exports of up to 2.5 bcf/day but new legal hurdles are continuing to delay progress. Apart from resurrecting the pipelines there is also the possibility of installing an LNG train or two.
And when one is considering the growing instability of the region, the next country down the list is Algeria, and that has now started to be mentioned among the countries feeling the fallout from the initial protests in Tunisia. The Algerian Foreign Minister is denying the risk of a “domino” effect. Possibly this could be because, as it is reported the income from oil and gas sales can, in this case help.
Unrest in Algeria could have implications on the world economy since it is a major oil and gas exporter, but analysts say an Egypt-style revolt is unlikely because the government can use its energy wealth to placate most grievances.There are, however, other opinions.
Algeria is a member of OPEC, which reports the January 2011 production of oil at 1.28 mbd, which has been relatively stable for some time. The EIA consider that the crude is some of the finest in the world . Production is supplemented by condensate (450 kbd in 2008) and NGL (357 kbd) for a total liquid fuels production of over 2 mbd. It is the largest oil-liquids producer in the African continent.
Algeria, which operates the oil and gas through the company Sonatrach exports most of its natural gas, through pipelines to Europe and through LNG terminals, with a new one that is to be completed in 2012. Total exports are around 2 TCF making it the fourth largest exporter. (CIA 2011 World Factbook). Gazprom has recently become involved in field development. It also provides a useful fuel for the processing of fertilizer in Morocco, as Jeff Vail noted, back in 2008. As one of the world’s largest exporters of natural gas, Algeria supplies Southern Europe.
The part of the Algerian gas in the gas balances in some European countries is significant. 86% for Portugal, 61% for Spain, 49% for Italy, 26% for Belgium, 25% for France and 21% for Turkey. Today about 97% of Algerian gas exports supply the European market next to Russia, and Norway, one of the main suppliers of the Europe. Algeria accounts for 29 percent of European Union gas imports and 15% of gas consumption
Algerian natural gas delivery network The Algerian reserves are found in the Sahara
• 67% of oil and gas reserves contained in the Oued Mya and HassiMessaoud areas, where the two giant fields Of Hassi Rmel (Gas) and Hassi Messaoud (Oil) are located.Algeria is hoping to increase exports by 50% by 2015, using a new pipeline into Spain to help develop the European market.
• The Illizi basin comes third with 14% of initial reserves;
Then come the basins of Rhourd Nouss (9%), Ahnet Timimoun (4%), and the Berkine basin.
But the current turmoil may make some of these plans moot.
Read more!
Friday, February 4, 2011
Natural gas shortages in the Southwest
The troubles with energy supply are not just confined to electric power blackouts in Texas. A shortage of natural gas in New Mexico has left 32,000 customers without a supply. Because the gas is supplied through pipelines that are kept at a fixed pressure to allow the gas to flow at sufficient volume, drops in either pressure or supplied volume will lower the amount coming out at the delivery end. This has led to a declared state of emergency with the governor urging that schools close in face of the cold and the shortage of fuel.
The problem with natural gas feeds, as opposed, for example to electricity, is that when supply is shut-off the flame that burns the gas goes out. Thus there is a safety protocol required to restore service:
The disruptions are not just confined to New Mexico. El Paso Natural Gas has declared “Force majeure” because of the constraints on supply. And frozen wellheads in Wyoming are reducing the flows available to customers in California. Just as with electric power, the utility answer is to shed some of the industrial load. Large industrial concerns get a lower price for their gas if they agree that it can be shut off in times where supply is no longer adequate. Such is now the case in San Diego where 88 companies have had their supplies curtailed as part of this program. Under normal circumstances the region is supplied through the Trans-western pipeline, which carries 2.4 Bcf/day.
It is reported that up to 5% of normal production has been temporarily lost both due to well head freeze-off and problems in the processing plants. And this is not all occurring in just the more northerly states.
(As an aside it is worth noting that the EIA is predicting that there will be an additional 4 Bcf of natural gas coming onto pipelines from the Marcellus shale by this November). Overall the wellhead freeze-offs and other problems lowered national gas production, on average, to around 62 bcf/day.
Wellhead freeze-off occurs because the natural gas coming out of the well contains a varying amount of water in the mix. When temperatures get cold enough then, even though the gas comes out of the ground quite warm, this water can freeze. (A gas is considered dry in the USA when it contains less than 7 lb of water per million scf). When it does it blocks the flow channels, and the well is shut-in until it thaws. That is the simplest case, and since we know the freezing temperature of water then that should tell us when it is going to happen. Unfortunately, as some of you may remember from the Gulf oil spill incident this last summer, there are also conditions when gas hydrates can form in the infrastructure. These can form and freeze at higher temperatures. More typically, however, it is the water vapor in the line which causes a problem. David Fish gives an example of what can happen.
The problem with natural gas feeds, as opposed, for example to electricity, is that when supply is shut-off the flame that burns the gas goes out. Thus there is a safety protocol required to restore service:
The process to restore natural gas service to homes and businesses is the most time-consuming aspect of any outage. We ask for your patience as we begin and complete the restoration process over the upcoming days.
What can our customers expect? The restoration process means visiting each home and business twice. First, every meter is shut off. Then, work begins on restoring gas in the large pipelines bringing natural gas to their area and make sure the system is operating safely. Finally, our crews will go door-to-door, revisiting every home and business, to turn the meters back on, perform critical safety checks and relight gas appliances. There may be a slight smell of gas in your neighborhood while technicians purge the meters.
Who will be relighting my appliance? Qualified, trained New Mexico Gas Company service technicians from around the state will be helping to restore service to affected areas in an orderly manner.
The disruptions are not just confined to New Mexico. El Paso Natural Gas has declared “Force majeure” because of the constraints on supply. And frozen wellheads in Wyoming are reducing the flows available to customers in California. Just as with electric power, the utility answer is to shed some of the industrial load. Large industrial concerns get a lower price for their gas if they agree that it can be shut off in times where supply is no longer adequate. Such is now the case in San Diego where 88 companies have had their supplies curtailed as part of this program. Under normal circumstances the region is supplied through the Trans-western pipeline, which carries 2.4 Bcf/day.
It is reported that up to 5% of normal production has been temporarily lost both due to well head freeze-off and problems in the processing plants. And this is not all occurring in just the more northerly states.
The unexpected drop in supplies from wells freezing off forced utilities and some looking to churn a quick profit to reach for gas in storage, forcing the company to set limits on withdrawals. At least 1.5 bcfd of production is offline in the East Texas, Fort Worth and Texas Gulf Coast basins, Bentek estimates, with at least 900 mmcfd offline in the Anadarko Basin, which lays partly in Texas and Oklahoma. 'Anadarko volumes being off makes a lot of sense,' said Matt Marshall, senior energy analyst with Bentek in Evergreen, Colorado. 'It got hit hard by the weather and it's liquids rich.'While supplies in storage should be more than adequate to meet demand, the problems arise in both getting this into the delivery pipelines, and then getting it to the customer. Or deciding which customer gets it. As the EIA noted in their latest (Feb 3rd) Natural Gas Weekly Update
Liquids-rich gas tends to freeze faster since it has a higher dew point, Marshall said.
The largest percent price increases during the week occurred in markets west of the Mississippi River, where there has been little price volatility this winter.In the Rockies and Midcontinent, where weather conditions were extreme and there were numerous reports of declines in production due to icing conditions at producing wells, price increases exceeded well over $1 per MMBtu or about 30 percent. BENTEK Energy, LLC, reported that flows on pipelines shifted significantly as higher demand in localized markets in the Rockies decreased flows on other pipelines that transport supplies out of the Rockies to the east, such as the Rockies Express Pipeline. In addition, numerous Midcontinent and Rockies area pipelines reported constraints on their systems, resulting in losses of flexibility to move gas between regions . . . . Prices in the Rockies increased at all trading locations. For example, the price for supplies on the Questar Corporation system in Utah increased $1.39 per MMBtu to $5.46, the highest price reported at this location this winter.
(As an aside it is worth noting that the EIA is predicting that there will be an additional 4 Bcf of natural gas coming onto pipelines from the Marcellus shale by this November). Overall the wellhead freeze-offs and other problems lowered national gas production, on average, to around 62 bcf/day.
Wellhead freeze-off occurs because the natural gas coming out of the well contains a varying amount of water in the mix. When temperatures get cold enough then, even though the gas comes out of the ground quite warm, this water can freeze. (A gas is considered dry in the USA when it contains less than 7 lb of water per million scf). When it does it blocks the flow channels, and the well is shut-in until it thaws. That is the simplest case, and since we know the freezing temperature of water then that should tell us when it is going to happen. Unfortunately, as some of you may remember from the Gulf oil spill incident this last summer, there are also conditions when gas hydrates can form in the infrastructure. These can form and freeze at higher temperatures. More typically, however, it is the water vapor in the line which causes a problem. David Fish gives an example of what can happen.
In a practical case you can have gas flowing in the pipeline at 60 degrees Fahrenheit and 700 psi and have no evidence of freezing. If you pass through a regulator station and cut the pressure to 225 psi, the flowing temperature at the point of regulation will drop 33 degrees Fahrenheit to approximately 27 degrees Fahrenheit. If the gas stream is saturated with water vapor and condensate, you will quickly experience the freezing concerns we are discussing.There are several ways in which this the supply can be protected from this happening – though in parts of the country where it doesn’t normally get this cold, they might not be cost effective. The first is to remove the water, which can be done using a variety of tools typically either a solid or liquid dessicant, alternately methanol can be trickled into the line, lowering the freezing temperature of the mix, hopefully below prevailing temperatures, and thirdly the system can be kept warm enough that it doesn’t freeze. The last two of these make some assumptions on how cold it is going to get. And if the temperature falls below that point, then they may become ineffective.
Read more!
Sunday, January 16, 2011
OGPSS - Natural Gas finds and production in Venezuela
In the last two Tech talks I have been discussing the production of heavy oil from the deposits in the Orinoco Basin in Venezuela. Production of that oil requires, in part, the injection of large quantities of natural gas. In writing about the resources that the country has, it would be remiss not to concurrently note the recent discoveries of additional volumes of natural gas offshore Venezuela, and the volumes that are thus available, not only for the oil fields, but also for a rising domestic consumption.
In November 2009, Repsol announced that the Perla 1X well had found the equivalent of between 1 and 1.4 boe of natural gas, said to be the fifth largest hydrocarbon discovery in 2009. (The other four, in debatable rank are Miran West (Iraq), Poseidon (Australia); Abare West in the Santos Basin (Brazil) and Tamar (Israel). You can argue about the size of some of the others – such as the Keathley Canyon discoveries in the GOM, since it depends on whose list (see slide 11) or other list you use.
Location of the initial Repsol natural gas discoveries off Venezuela.
Since then additional drilling reported by ENI, in the same Cardon IV block, has confirmed that this is a giant field, with a potential size of 2.5 billion boe (14 Tcf of natural gas). To clarify who owns what:
Source Energy Export Databrowser
That import comes about because of the Antonio Ricaurte gas pipeline that was constructed between Venezuela and Colombia. Begun in 2006, at a cost of $467 million to PdVSA, the 140-mile long pipeline was finished in 2007 with the initial idea that natural gas would first flow from Colombia to Venezuela, but then, within four to seven years, as the infrastructure in Venezuela improved, and the Guajira gas fields in Colombia decline, it would flow the other way. It has not had a totally smooth history, since just over a year ago Colombia reduced the flow, in part due to a rise in local demand.
Oil (green) and natural gas (red) pipelines in Venezuela. (Source Theodora)
The fields that are supposed to provide the surplus natural gas and thus to allow the flow to Colombia after 2012 included those of the Mariscal Sucre project to the East.
Location of the Mariscal Sucre project
However when, most recently, bids were first issued for that project last January there were no bids. As Wiki-leaks found, this was somewhat upsetting to the Venezuelan government, who need the natural gas to pump into the oilfields and maintain the pressure needed for production. The problem appeared to relate to the price to be paid for the natural gas, relative to the $8 billion development cost.
In the end PdVSA decided to go forward with the project themselves, using the Aban Pearl semi-submersible owned by an Indian-based company . But, back in May the semi-submersible sank, a week after igniting the gas flare at the beginning of the development. Initially, back in 2002, that project was to have been run by a partnership between PdVSA, Shell and Misubishi, as part of an LNG project. This was scaled back and PdVSA began to develop the project alone. At the time of the sinking the rig was drilling in the Dragon area of the project, slated to produce between 600 and 700 mcf/day, with an ultimate target for the project of 1.2 bcf/day. The field (ultimately possibly of 8 wells) would deliver to shore through a 70-mile undersea pipeline. Since the sinking of the rig, PdVSA has contracted with Technip to build a production platform for the field, with construction planned so that the original target of production by 2012 could still be met.
Venezuela still has a large potential for producing natural gas, and from time to time has talked of developing LNG facilities to export some of this. The EIA cites three possible developments that were discussed in 2008, with the trains supplied from fields at Plataforma Deltana, Mariscal Sucre, and Blanquilla-Tortuga. Two years later Iran has just signed an agreement to help with the Delta Caribe project (which covers the first two trains) but while scheduled for 2014 it is interesting to note (along the lines of the swap arrangement that I mentioned in regard to Venezuelan oil last week) the first paragraph in the following release.
In November 2009, Repsol announced that the Perla 1X well had found the equivalent of between 1 and 1.4 boe of natural gas, said to be the fifth largest hydrocarbon discovery in 2009. (The other four, in debatable rank are Miran West (Iraq), Poseidon (Australia); Abare West in the Santos Basin (Brazil) and Tamar (Israel). You can argue about the size of some of the others – such as the Keathley Canyon discoveries in the GOM, since it depends on whose list (see slide 11) or other list you use.
Location of the initial Repsol natural gas discoveries off Venezuela.Since then additional drilling reported by ENI, in the same Cardon IV block, has confirmed that this is a giant field, with a potential size of 2.5 billion boe (14 Tcf of natural gas). To clarify who owns what:
The Cardon IV Block is currently licensed and operated by a Joint Operating Company named Cardon IV S.A. which is 50% owned by Eni and 50% by Repsol. The Venezuelan state company Petroleos de Venezuela S.A. (PDVSA) owns a 35% back-in right to be exercised in the development phase, and at that time Eni and Repsol will each hold a 32.5% interest in the project, which will then be jointly operated by the three companies.Given that the field is in relatively shallow water (70 m) it is anticipated that an initial production of some 300 mcf/day can be brought ashore and pipelined, by 2013. Now this may sound quite a bit, but Venezuelan production has been declining, to the point that the country has started to import natural gas.
Source Energy Export DatabrowserThat import comes about because of the Antonio Ricaurte gas pipeline that was constructed between Venezuela and Colombia. Begun in 2006, at a cost of $467 million to PdVSA, the 140-mile long pipeline was finished in 2007 with the initial idea that natural gas would first flow from Colombia to Venezuela, but then, within four to seven years, as the infrastructure in Venezuela improved, and the Guajira gas fields in Colombia decline, it would flow the other way. It has not had a totally smooth history, since just over a year ago Colombia reduced the flow, in part due to a rise in local demand.
Oil (green) and natural gas (red) pipelines in Venezuela. (Source Theodora) The fields that are supposed to provide the surplus natural gas and thus to allow the flow to Colombia after 2012 included those of the Mariscal Sucre project to the East.
Location of the Mariscal Sucre projectHowever when, most recently, bids were first issued for that project last January there were no bids. As Wiki-leaks found, this was somewhat upsetting to the Venezuelan government, who need the natural gas to pump into the oilfields and maintain the pressure needed for production. The problem appeared to relate to the price to be paid for the natural gas, relative to the $8 billion development cost.
In the end PdVSA decided to go forward with the project themselves, using the Aban Pearl semi-submersible owned by an Indian-based company . But, back in May the semi-submersible sank, a week after igniting the gas flare at the beginning of the development. Initially, back in 2002, that project was to have been run by a partnership between PdVSA, Shell and Misubishi, as part of an LNG project. This was scaled back and PdVSA began to develop the project alone. At the time of the sinking the rig was drilling in the Dragon area of the project, slated to produce between 600 and 700 mcf/day, with an ultimate target for the project of 1.2 bcf/day. The field (ultimately possibly of 8 wells) would deliver to shore through a 70-mile undersea pipeline. Since the sinking of the rig, PdVSA has contracted with Technip to build a production platform for the field, with construction planned so that the original target of production by 2012 could still be met.
Venezuela still has a large potential for producing natural gas, and from time to time has talked of developing LNG facilities to export some of this. The EIA cites three possible developments that were discussed in 2008, with the trains supplied from fields at Plataforma Deltana, Mariscal Sucre, and Blanquilla-Tortuga. Two years later Iran has just signed an agreement to help with the Delta Caribe project (which covers the first two trains) but while scheduled for 2014 it is interesting to note (along the lines of the swap arrangement that I mentioned in regard to Venezuelan oil last week) the first paragraph in the following release.
The official added that Venezuela has long-term contracts with Argentina and Cuba to supply the countries with their required gas by 2013, noting that under the agreements inked between Tehran and Caracas part of their gas needs will be procured by Iran's LNG plant.Whether the LNG terminals get built is still likely a dubious question. The world market for LNG is becoming more readily supplied, though to a degree that depends on how the domestic production in the USA shakes out. (And the development of shale gas in countries such as Argentina). As a result though Venezuela continues to find large quantities of natural resources, it will be the investment that brings these products to market in a timely manner that will validate the continuing promise of increased production at some future date.
Kheirandish stated that 40 percent of the project to construct Iran LNG plant is completed, expressing hope that the project will be half complete by the end of the current Iranian calendar year (March 20, 2011).
According to the Letter of Intent signed between Iran and Venezuela, Tehran will help Caracas to build an LNG plant in Delta Caribe area, and Venezuela will also cooperate with the Islamic Republic to build an Iranian LNG plant in Venezuela with an annual production capacity of 5.4 million tons.
Read more!
Sunday, December 19, 2010
OGPSS - pipelines, a help that can be costly
I have written about the limitations in the free flow of oil because of the increasingly heavy and sour nature of the reserves that are now being developed, and the need for suitable refineries to process that oil. I then wrote about how it’s not just oil from oilwells, but also the non-gas-liquids (NGLs) that count toward the total volume of oil that is consumed in the world. There are other constraints to production, and the one that I’m going to talk about today is that of transportation. It seemed appropriate at a time when Chevron has just announced a doubling of the size of the pipeline from the Tengiz field in western Kazakhstan to Novorosslysk on the Black Sea. It will now carry some 1.4 mbd of oil to the port, whence it will be transshipped in tankers.
Transportation is, of course, a major problem for many energy forms, as Leanan caught, the Chinese are already facing problems this winter over the distribution of power.
The oil and gas industries flourish largely because of these pipelines, which carry liquids easily over long distances. Perhaps the most famous is the pipeline that carries oil from the North Slope to Valdez. It has survived the varying Alaskan weather conditions, passing over permafrost and rivers, or being buried, depending on the geology. It was the only viable way to effectively develop that reserve.
Alaskan pipeline just North of Fairbanks. Note the radiators on the support legs. These disperse the heat from the pipe (and the oil) which keep the permafrost, in which the support legs sit, from melting. The 48-inch line was sized to carry 2.1 mbd of oil. Today it only carries around 660,000 bd.
Pipelines don’t just allow reserves to be extracted, consider the Rockies Express Pipeline that is bringing natural gas from Colorado through the 1,679 miles to Ohio. Before it was installed Colorado would have a surplus of natural gas in the winter, while the North East had a shortage. To a degree (Caribou Maine being still some distance from Ohio) that has now been ameliorated.
The pipeline route (Kinder Morgan )
Pipelines need to be sized for the volumes that flow. In order that the oil/gas flow down the pipe the fluid is pumped into the line at pressure, and at stages along the pipe, as the pressure is “used up” on overcoming friction from the pipe walls, there are booster stations that raise the pressure back to the driving pressure, to keep it moving. (And yes these use some of the fuel, particularly if it is gas, as a power source).
One of the problems with running the pipe under that pressure is that if there is any corrosion or damage to the pipe then the pressure may have to be lowered to stop the pipe from bursting. Since the flow velocity is a function of the square root of this driving pressure, then as the pressure drops so does the volume pumped.
As a result inspection to make sure there is little or no corrosion should be a regular feature of pipeline maintenance. Given that the pipe can run for miles above or below the surface, external inspection can be difficult, and, instead companies will run “pigs” down the line. (The name comes from the “squeal” as they move) These are put into the pipe at the “top” end and pumped down with the oil. Instruments and sensors within the central compartment can monitor conditions as the pig moves. Pigs are also fitted with wipers the ensure that deposits from the fluid don’t build up along the pipe and cause problems.
Example pig used in the Alaskan pipeline – see the wipers and note the central compartment within the pig.
It is difficult to stop all corrosion, and over time segments of the pipe may need to be replaced because of damage that can build up in the normal course of operations. If inspections are not regular, then, as BP found in 2006, corrosion can lead to a leak, and big problems.
Unfortunately pipelines are not just prone to mechanical problems. Their presence is hard to hide, and thus, become targets for theft. Whether in Mexico this weekend, or Nigeria almost every day, theft by physically extracting fuel from pipelines can be a very dangerous game, with explosions and loss of life a not-infrequent result.
And that is just the small scale operations. On a larger scale the risk can be a lot less. Remember that Western Europe is becoming increasingly dependent on Russian natural gas for supplies, particularly in the winter months. That natural gas travels between the two passing down a pipeline through Ukraine. The financial woes of that country meant that it did not always pay its gas bill, and, usually in January, this led to confrontations between Russia and Ukraine, with Western Europe the frequent loser. To overcome this dependence Russia is now putting in place two smaller pipelines that will circumvent Ukraine to the North (Nordstream) and the South.
One of the key players in that game was Turkmenistan, which supplied its natural gas through pipelines that only went through Russia to their customers. Russia for years was able to dictate the price that it paid Turkmenistan, often considerably less than it was getting from Europe. But since it was the only game in town . . . .
That recently changed, however, with the construction of a pipeline from Turkmenistan to China and this broke the monopoly that Russia held over the sale of Turkmen gas. The pipeline is now being upgraded and the flow increased to 1.25 billion cu ft/day, four times the volume that flowed, on average, last year. The pipeline is 4,350 miles long. Ultimately the flow will be three times that size – about the volume that Turkmenistan used to sell to Russia. (The last reference has the picture of what may be the one Soviet attempt to extinguish a burning gas fire with a nuclear device that didn’t work).
The Russians haven’t forgotten the benefits that come from owning the pipelines and the control that this gives over the producers. BP learned that lesson the hard way. Gazprom is the Russian company that owns the pipelines (and on a slow news day I could always find a story by seeing what new machinations had been revealed in a Google seach for Gazprom). By controlling the pipelines they could dictate what flowed when. As an example let me remind you of the situation that BP faced in developing the Kovykta gas field back in 2007. The deal was that after BP developed the field, they had to produce 9 billion cubic meters (bcm) per year, as the license stipulated. But local consumers could only handle a small fraction of this, and Gazprom, who owned the only pipeline in town, was only willing to allow a flow of 1.7 bcm. Oops! You guessed it, BO was held liable for not meeting the terms of the license and . . . . .
You will note that Gazprom has been quite efficient at getting control of a large portion of the pipelines and (as a result) the distribution networks across Europe.
That story brings to mind another caveat, that illustrates the bind that pipeline owners can impose on their clients. Bear in mind that these pipelines are not cheap, and while they can be installed relatively rapidly, they have to be paid for. Thus, before they are installed the owners require long-term commitments from both the seller at one end and the vendor at the other. The Rockies Express has such commitments.
However, if the pipeline owner then changes the rules, there is not a whole lot that the other two partners can do – as a whole list of countries who have been squeezed by Russia would be glad to remind you.
But it is not just over Russia that the world should have a concern. One should not forget the new pipelines that are being constructed across Asia. Whether the Chinese pipeline from Turkmenistan, or the TAPI pipeline from Turkmenistan to India, these mark a switch in the destiny of future fuel production. It is a future that means that a considerable volume of the worlds fuel may no longer be available to the West. And where that fuel is natural gas, and the nations of Europe are building gas-fired power plants to back-up wind and other renewable sources, then if the gas isn’t there . . . . .
No problem, you say, old HO is being his usual alarmist self. Well you might want to note how many times this winter there is a “Gas Balancing Alert” action in the UK. Rune Likvern has already highlighted the start of a possible problem as stocks were drawn down at the start of the winter and it has not got any better. The first Alert has been issued for this season.
Further information can be found on the National Grid Website. The normal daily usage at this time of year, according to that site, is 364 million scm (standard cubic meters). The trigger for a GBA is 452 mscm, and tomorrow’s demand is forecast at 463 mscm. Interruptions seem most likely to occur in the North.
Oh, and just to give you a better sense of the scale of some of these pipes - here is me beside the one in Alaska.
Transportation is, of course, a major problem for many energy forms, as Leanan caught, the Chinese are already facing problems this winter over the distribution of power.
Most of China's resource production bases, including coal and and oil, are either concentrated in the northern or western provinces, away from the key demand areas located in the southern and eastern region, such as Shanghai and Guangdong.And it turns out that they are not the only ones. As the new snowfall wraps over the United Kingdom there are concerns over the distribution of fuel oil.
Any supply shortfall could prompt a surge in import demand as utilities and firms seek alternative fuel supplies to feed their power plants.
Downing Street was forced to respond to reports that heating oil might need to be rationed over the winter because of rocketing prices and restricted deliveries, admitting there was a problem moving it around the country.All of which serve to emphasize a point that I wanted to make today about how the presence of a pipeline can, but not always, help the situation.
The energy minister, Charles Hendry, sparked alarm yesterday when he warned the House of Commons that the situation could become "very serious" if there was further snow over the Christmas period.Thousands of public buildings and an estimated 660,000 homes rely on oil for heating and Hendry told MPs some had been told supplies would not be available for four weeks.
The oil and gas industries flourish largely because of these pipelines, which carry liquids easily over long distances. Perhaps the most famous is the pipeline that carries oil from the North Slope to Valdez. It has survived the varying Alaskan weather conditions, passing over permafrost and rivers, or being buried, depending on the geology. It was the only viable way to effectively develop that reserve.
Alaskan pipeline just North of Fairbanks. Note the radiators on the support legs. These disperse the heat from the pipe (and the oil) which keep the permafrost, in which the support legs sit, from melting. The 48-inch line was sized to carry 2.1 mbd of oil. Today it only carries around 660,000 bd. Pipelines don’t just allow reserves to be extracted, consider the Rockies Express Pipeline that is bringing natural gas from Colorado through the 1,679 miles to Ohio. Before it was installed Colorado would have a surplus of natural gas in the winter, while the North East had a shortage. To a degree (Caribou Maine being still some distance from Ohio) that has now been ameliorated.
The pipeline route (Kinder Morgan ) Pipelines need to be sized for the volumes that flow. In order that the oil/gas flow down the pipe the fluid is pumped into the line at pressure, and at stages along the pipe, as the pressure is “used up” on overcoming friction from the pipe walls, there are booster stations that raise the pressure back to the driving pressure, to keep it moving. (And yes these use some of the fuel, particularly if it is gas, as a power source).
One of the problems with running the pipe under that pressure is that if there is any corrosion or damage to the pipe then the pressure may have to be lowered to stop the pipe from bursting. Since the flow velocity is a function of the square root of this driving pressure, then as the pressure drops so does the volume pumped.
As a result inspection to make sure there is little or no corrosion should be a regular feature of pipeline maintenance. Given that the pipe can run for miles above or below the surface, external inspection can be difficult, and, instead companies will run “pigs” down the line. (The name comes from the “squeal” as they move) These are put into the pipe at the “top” end and pumped down with the oil. Instruments and sensors within the central compartment can monitor conditions as the pig moves. Pigs are also fitted with wipers the ensure that deposits from the fluid don’t build up along the pipe and cause problems.
Example pig used in the Alaskan pipeline – see the wipers and note the central compartment within the pig.It is difficult to stop all corrosion, and over time segments of the pipe may need to be replaced because of damage that can build up in the normal course of operations. If inspections are not regular, then, as BP found in 2006, corrosion can lead to a leak, and big problems.
Unfortunately pipelines are not just prone to mechanical problems. Their presence is hard to hide, and thus, become targets for theft. Whether in Mexico this weekend, or Nigeria almost every day, theft by physically extracting fuel from pipelines can be a very dangerous game, with explosions and loss of life a not-infrequent result.
And that is just the small scale operations. On a larger scale the risk can be a lot less. Remember that Western Europe is becoming increasingly dependent on Russian natural gas for supplies, particularly in the winter months. That natural gas travels between the two passing down a pipeline through Ukraine. The financial woes of that country meant that it did not always pay its gas bill, and, usually in January, this led to confrontations between Russia and Ukraine, with Western Europe the frequent loser. To overcome this dependence Russia is now putting in place two smaller pipelines that will circumvent Ukraine to the North (Nordstream) and the South.
One of the key players in that game was Turkmenistan, which supplied its natural gas through pipelines that only went through Russia to their customers. Russia for years was able to dictate the price that it paid Turkmenistan, often considerably less than it was getting from Europe. But since it was the only game in town . . . .
That recently changed, however, with the construction of a pipeline from Turkmenistan to China and this broke the monopoly that Russia held over the sale of Turkmen gas. The pipeline is now being upgraded and the flow increased to 1.25 billion cu ft/day, four times the volume that flowed, on average, last year. The pipeline is 4,350 miles long. Ultimately the flow will be three times that size – about the volume that Turkmenistan used to sell to Russia. (The last reference has the picture of what may be the one Soviet attempt to extinguish a burning gas fire with a nuclear device that didn’t work).
The Russians haven’t forgotten the benefits that come from owning the pipelines and the control that this gives over the producers. BP learned that lesson the hard way. Gazprom is the Russian company that owns the pipelines (and on a slow news day I could always find a story by seeing what new machinations had been revealed in a Google seach for Gazprom). By controlling the pipelines they could dictate what flowed when. As an example let me remind you of the situation that BP faced in developing the Kovykta gas field back in 2007. The deal was that after BP developed the field, they had to produce 9 billion cubic meters (bcm) per year, as the license stipulated. But local consumers could only handle a small fraction of this, and Gazprom, who owned the only pipeline in town, was only willing to allow a flow of 1.7 bcm. Oops! You guessed it, BO was held liable for not meeting the terms of the license and . . . . .
You will note that Gazprom has been quite efficient at getting control of a large portion of the pipelines and (as a result) the distribution networks across Europe.
That story brings to mind another caveat, that illustrates the bind that pipeline owners can impose on their clients. Bear in mind that these pipelines are not cheap, and while they can be installed relatively rapidly, they have to be paid for. Thus, before they are installed the owners require long-term commitments from both the seller at one end and the vendor at the other. The Rockies Express has such commitments.
REX is a joint venture of KMP (we own 50 percent and operate the pipeline), Sempra Pipelines and Storage and ConocoPhillips. Long-term, binding firm commitments have been secured for virtually all of the pipeline's capacity. The pipeline is enabling producers to deliver gas from the Rocky Mountains eastward and is helping to ensure that there will be adequate supplies of natural gas to meet growing demand in the Midwest and eastern parts of the country.There is an underlying point here that is sometimes missed when these projects are discussed, and that is that the agreements between all parties will usually establish a price for the product, at the time that the contracts are signed, that run well into the future. Those prices do not reflect the current market price of the fuel. It is a point that often gets overlooked in discussions over fuel distribution. But many of the ways in which fuel is shipped require considerable investments not only for the production, but also for the transportation, and then for the distribution. Thus the need for commitment and guarantees before the process of construction begins. (This has just been evident in the wait in starting new coal mines in Australia, for example, until long-term contracts with China had been signed.)
However, if the pipeline owner then changes the rules, there is not a whole lot that the other two partners can do – as a whole list of countries who have been squeezed by Russia would be glad to remind you.
But it is not just over Russia that the world should have a concern. One should not forget the new pipelines that are being constructed across Asia. Whether the Chinese pipeline from Turkmenistan, or the TAPI pipeline from Turkmenistan to India, these mark a switch in the destiny of future fuel production. It is a future that means that a considerable volume of the worlds fuel may no longer be available to the West. And where that fuel is natural gas, and the nations of Europe are building gas-fired power plants to back-up wind and other renewable sources, then if the gas isn’t there . . . . .
No problem, you say, old HO is being his usual alarmist self. Well you might want to note how many times this winter there is a “Gas Balancing Alert” action in the UK. Rune Likvern has already highlighted the start of a possible problem as stocks were drawn down at the start of the winter and it has not got any better. The first Alert has been issued for this season.
On Monday the National Grid issued a gas balancing alert (GBA) for only the second time, asking power suppliers to use less gas as more was sourced overseas. Extra gas - including supplies from Belgium and Norway - was necessary to meet rising demand after a 30% rise on normal seasonal use during the cold snap.This is only the second such alert, the first coming last January.
Further information can be found on the National Grid Website. The normal daily usage at this time of year, according to that site, is 364 million scm (standard cubic meters). The trigger for a GBA is 452 mscm, and tomorrow’s demand is forecast at 463 mscm. Interruptions seem most likely to occur in the North.
Oh, and just to give you a better sense of the scale of some of these pipes - here is me beside the one in Alaska.
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