Showing posts with label BP. Show all posts
Showing posts with label BP. Show all posts

Thursday, February 14, 2013

OGPSS - Ukraine moves to escape Gazprom's grip

You know it is winter when Russia and Ukraine publically row about supplies of natural gas. On Tuesday Ukraine completed the signing of an agreement with Turkmenistan for the supply of natural gas. In the past the purchases have been for up to 36 billion cu m per year, although this was historically through Russian intermediaries. That deal ended in 2006, and Turkmenistan has been able to find a customer in China that now provides an alternate sale that does not leave it dependent on whatever price Russia was willing to provide.

But this does not mean that Ukraine has been able to escape having to pay whatever price Russia wished to impose, since to get from Turkmenistan to Ukraine the natural gas still requires passage through a pipeline that runs through Kazakhstan and Russia. There is no prize for guessing that Gazprom owns those pipelines.


Figure 1. The Central Asia Center pipeline and the route of the projected Pre-Caspian pipeline – both owned by Gazprom. (Gazprom).

This continues to give Gazprom leverage over Ukraine, and with the North Stream pipeline now approaching its full potential after the second string was commissioned last October, Europe can receive up to 55 billion cu m per year without the gas having to pass through Ukraine.


Figure 2. Path of the North Stream (NordStream) pipeline from Russia to Germany (Gazprom)

There is now talk of adding additional capacity so that there can be a direct feed from Russia to the UK. BP is taking the lead on this, apparently with Gazprom support, although previous experience would suggest that Gazprom may end up as the major shareholder in the end, after all the bills have been paid. And speaking of which, their current dispute with Ukraine involves payment for $7 billion worth of natural gas,that Ukraine contracted for but did not, in the end use during 2012. Ukraine is paying $430 per thousand cubic meters ($12.18 per thousand cu ft) for a fixed volume per year, whether they use it or not, under an agreement signed in 2009.

There is some implication that this pressure may be related to the recent 50-year production sharing agreement that Ukraine signed with Shell to develop natural gas from shale deposits. The country is believed to have the third largest shale-bound natural gas resource in Europe (behind France and Norway ) estimated at around 42 trillion cu ft (1.2 trillion cu m).

The deposits are centered around the Yuzivskaya region, with production anticipated to start in 2017, rising to levels of around 8 – 10 bcm in ten years. Although there is some domestic opposition to the development, the schedule is aggressive.
Shell is to work with Nadra Yuzivska, a joint venture in which the state-owned resources company Nadra Ukrayiny owns 90%. SPK-Geoservice, a small private company, owns the remaining 10% in Nadra Yuzivska.

Shell is expected to invest $410 million to drill the first 15 wells, Oleh Proskuriakov, the environment and natural resources minister, said earlier in January.

The total area of the Yuzivska field is 7,886 sq km. The deposit could hold 4.05 Tcm of gas, according to the government. Proskuriakov has also projected output from Yuzivska could hit 10 Bcm/year in 10 years and 20 Bcm/year in 15. Ukraine's Stavytskiy characterized the latter figure as representing the "optimistic scenario."

"We can project that in an optimistic scenario, the project will produce 20 Bcm/year of gas, while under a pessimistic scenario, 7-8 Bcm/year," Stavytskiy said.
An adjacent well drilled by Hutton has shown promising signs of “interpreted pay in three intervals.”

Chevron is expected to develop deposits in the Olesska region with start dates of around the same time. Opposition to their plans seems to be growing, and they have yet to sign a production sharing agreement. They are, however hoping to get the same sort of deal that Shell negotiated.

It is worth injecting a note of caution into this optimistic view of the future. Just a year ago Poland was anticipating a similar bonanza from the natural gas in its shale deposits. Events have limited that dream. Although a 2011 EIA report stated that Poland had 187 tcf of technically recoverable natural gas, the Polish Geological Institute has now cut the estimates of the viable size of the resource by 90%, and there are other problems.
Difficult geology, an uncompetitive service sector, poor infrastructure, and lack of rigs have hampered development. Poland has a venerable oil and gas sector, but most of the transmission pipelines are based in the southwest, while major shale gas areas are in the northeast. Strict EU environmental laws, as well as unclear regulatory and tax frameworks have further eroded prospects. And while exploration has been going on for a few years now, only 33 wells have been drilled, with just eight of them fracked (at least 200 would have to be drilled in the exploratory stage, just to assess the actual size of reserves).

Preliminary results have not been encouraging, either: This summer, resource giant ExxonMobil withdrew from Poland after the failure of commercial gas flows, while its competitor ConocoPhillips decided not to exercise its 70 percent option in three concessions in northern Poland. Overall, costs per well have increased to $15 million, according to interviews with industry officials, roughly three times the cost in the United States.
And there are two more factors that should be considered. Ukraine is planning an LNG plant on the Black Sea to be ready by 2015, but even this is controversial. To reach the Black Sea tankers will have to pass through the Bosphorus and Dardanelles straits, and Turkey has intimated that it may not allow LNG tankers rights to that passage. That is because the terminal would compete with two that already exist in Turkey.

Secondly Ukraine is working with the Chinese to gasify some of their coal from their large deposits, with the intent of producing the equivalent of 4 bcm of natural gas to displace Russian imports.
The projects are two-fold: first, heat-producing facilities will be converted to use coal-water slurry as fuel; second, new plants will be built to enable the gasification of brown and bituminous coal in three regions: Luhansk, Donetsk and Odessa. While most of the media reports claim that Ukraine will be using Chinese coal-slurry technology, it’s actually Shell’s technology.
How soon Ukraine (and Poland) can stop imports of energetic fuels from Russia is not clear, but obviously this should happen before long, and the winters of their discontent may well disappear from the headlines.

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Posted by Heading Out at 11:09 PM 0 comments
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Thursday, June 28, 2012

OGPSS - The Harvard Energy Report, another cough

The OGPSS posts of the last few months have been following a path of looking in a relatively realistic manner at crude oil production with emphasis on that coming from the United States, Russia and Saudi Arabia – the current focus of the weekly pieces. An earlier piece, looked at a Citigroup report of considerable optimism, and the post explained why, in reality, it is impractical to anticipate much increase in US production this decade. Since then, after reviewing the production from Russia, several posts have shown why their current lead in daily crude oil production is likely to be soon over, and that Russian production will then decline, as the oil companies are not bringing new fields on line as fast as the old ones are running out. Saudi Arabia, as the current section of posts are in the process of explaining, is unlikely to increase production much beyond 10 mbd, since Ghawar, the major field on which its current production level is built, is reaching the end of its major contribution, though it will continue to produce at a lower rate into the future. The bottom line, at least to date, is that there is no evidence from the top 3 producers that their production will be even close, in total, to current levels by the end of the decade.
 So, (h/t Leanan) there now comes an Energy Study from Harvard which boldly states that this is rubbish, and that by 2020 global production will be at 110.6 mbd and these concerns that most of us have at The Oil Drum (inter alia) are chimeras of the imagination.
Figure 1. Anticipated Growth in global oil production by the end of the decade (Maugeri, Leonardo. “Oil: The Next Revolution” Discussion Paper 2012-10, Belfer Center for Science and International Affairs, Harvard Kennedy School, June 2012. )
It is therefore pertinent to begin with examining where the study (which was prepared with BP assistance) anticipates that the growth in supply will come from. 
 That too is shown as a plot: 
  
Figure 2. Anticipated sources of the growth in global production by 2020 (showing only the top 23 producers). ((Maugeri, Leonardo. “Oil: The Next Revolution” Discussion Paper 2012-10, Belfer Center for Science and International Affairs, Harvard Kennedy School, June 2012.) 
 It is instructive, in reading this plot, to first recognize that it is a plot of anticipated production capacity, rather than projected actual production. The reason for this can perhaps be illustrated by an example. Within the current production capacity that Saudi Arabia claims adds up to 12 mbd is the 900 kbd that will come from Manifa as it is further developed and comes on line within the next few years. However at that time the increase in production is going, to some degree, to offset the declines in existing wells and producing fields that will become more severe as more of existing horizontal wells water out. Manifa is not currently in significant production, and is unlikely to be at such a level for at least another 18-months, with production being tied to the construction of the two new refineries being built to handle the oil. It is not therefore a currently instantaneously available source of oil. At a relatively normal 5% per year decline in production from existing fields, Saudi Arabia will have to bring on line (and sustain) at least 500 kbd per year of new production, and while it is likely that it can do this for a year or two more, betting that it will be able to do this and to raise production 2 mbd or more in 2020 is on the far side of optimistic. Just because a reserve exists does not mean that it can be brought on line without the physical facilities in place to produce it. 
 It is interesting, however, to note the report’s view on field declines in production:
Throughout recent history, there is empirical evidence of depletion overestimation. From 2000 on, for example, crude oil depletion rates gauged by most forecasters have ranged between 6 and 10 percent: yet even the lower end of this range would involve the almost complete loss of the world’s “old” production in 10 years (2000 crude production capacity = about 70 mbd). By converse, crude oil production capacity in 2010 was more than 80 mbd. To make up for that figure, a new production of 80 mbd or so would have come on-stream over that decade. This is clearly untrue: in 2010, 70 percent of crude oil production came from oilfields that have been producing oil for decades. As shown in Section 4, my analysis indicates that only four of the current big oil suppliers (big oil supplier = more than 1 mbd of production capacity) will face a net reduction of their production capacity by 2020: they are Norway, the United Kingdom, Mexico, and Iran. Apart from these countries, I did not find evidence of a global depletion rate of crude production higher than 2-3 percent when correctly adjusted for reserve growth.
Sigh! I explained last time that with the change in well orientation from vertical to horizontal, that there was a change in the apparent decline rates. This is because when the wells run horizontally at the top of the reservoir that they are no longer reduced in productive length each year, as vertical wells are, as the driving water flood slowly fills the reservoir below the oil as it is displaced. This does not mean that though the apparent decline rate from the well has fallen that it will, in the ultimate, produce more oil.
 The amount of oil in the region tapped by the well is finite, and when it is gone it is gone, whether from a vertical well that shows that gradual decline with time, or from the horizontal well that holds the production level until the water hits the well and it stops. I am not sure that the author of the report understands this. 
 The point concerning support logistics is critical in a number of instances. The political difficulties in increasing production from the oil sands in Alberta, through constraints on pipeline construction either South or West, are at least as likely to restrict future growth of that deposit as any technical challenge. The four countries that the report sees contributing most to future oil supplies are (in the ranked order) Iraq; the United States; Canada and Brazil. For Iraq he sees production possibly coming from the following fields, within the next eight years. 
   
Figure 3. Anticipated production gains in Iraq in the next eight years. (Maugeri, Leonardo. “Oil: The Next Revolution” Discussion Paper 2012-10, Belfer Center for Science and International Affairs, Harvard Kennedy School, June 2012. )
 I understand that one ought to show some optimism at some point over Iraq, but it has yet to reach the levels of production that it achieved before the Iran:Iraq War, and that was over some time ago. The EIA has shown that it is possible to get a total of over 13 mbd of production, but it requires investment and time, and some degree of political stability in the country. That is still somewhat lacking. Prior to that war Iraq was producing at 3.5 mbd, the production curve since then has not been encouraging:

Figure 4. History of Iraqi Production since the start of the Iran:Iraq War. (EIA) 
 Recognizing that the country has problems, the report still expects that there will be a growth in production of some 5.125 mbd by the end of the decade. This appears to be a guess as to being some 50% of the 10.425 mbd that the country could potentially achieve. 
 As for US production, this is tied to increasing production from all the oil shales in the country, which will see spurts in growth similar to that seen in the Bakken and Eagle Ford.
I estimate that additional unrestricted production from shale/tight oil might reach 6.6 mbd by 2020, or an additional adjusted production of 4.1 mbd after considering risk factors (by comparison, U.S. shale/tight oil production was about 800,000 bd in December 2011). To these figures, I added an unrestricted additional production of 1 mbd from sources other than shale oil that I reduced by 40 percent considering risks, thus obtaining a 0.6 mbd in terms of additional adjusted production by 2020. In particular, I am more confident than others on the prospects of a faster-than-expected recovery of offshore drilling in the Gulf of Mexico after the Deepwater Horizon disaster in 2010.
As I noted in my review of the Citicorp report this optimism flies in the face of the views of the DMR in North Dakota – who ought to know, since they have the data. The report further seems a little confused on how horizontal wells work in these reservoirs. As Aramco has noted, one cannot keep drilling longer and longer holes and expect the well production to double with that increase in length. Because of the need to maintain differential pressures between the reservoir and the well, there are optimal lengths for any given formation. And, as I have also noted, the report flies in the face of the data on field production from the deeper wells of the Gulf of Mexico. 
 It seems pertinent to close with the report’s list of assumptions on which the gain in oil production from the Bakken is based:
*A price of oil (WTI) equal to or greater than $ 70 per barrel through 2020 
*A constant 200 drilling rigs per week; 
*An estimated ultimate recovery rate of 10 percent per individual producing well (which in most cases has already been exceeded) and for the overall formation; 
*An OOP calculated on the basis of less than half the mean figure of Price’s 1999 assessment (413 billion barrels of OOP, 100 billion of proven reserves, including Three Forks). Consequently, I expect 300 billion barrels of OOP and 45 billion of proven oil reserves, including Three Forks; 
*A combined average depletion rate for each producing well of 15 percent over the first five years, followed by a 7 percent depletion rate; 
*A level of porosity and permeability of the Bakken/Three Forks formation derived from those experienced so far by oil companies engaged in the area. 
Based on these assumptions, my simulation yields an additional unrestricted oil production from the Bakken and Three Forks plays of around 2.5 mbd by 2020, leading to a total unrestricted production of more than 3 mbd by 2020.
Enough, already! There are too many unrealistic assumptions to make this worth spending more time on. To illustrate but one of the critical points - this is the graph that I have shown in earlier posts of the decline rate of a typical well in the Bakken. You can clearly see that the decline rate is much steeper than 15% in the first five years.Figure 5. Typical Bakken well production (ND DMR )  
Oh, on a related note the Alaskan pipeline was running at an average of 571,462 bd in May.

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Posted by Heading Out at 10:04 PM 4 comments
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Wednesday, July 27, 2011

OGPSS - Gulf of Mexico production, and hurricanes

The summer brings back Hurricane season, with the threat that such storms bring to the oil and gas well operations in the Gulf of Mexico. And the National Oceanic and Atmospheric Administration (NOAA) has noted that
The Atlantic basin is expected to see an above-normal hurricane season this year, according to the seasonal outlook issued by NOAA’s Climate Prediction Center . . . . 3 to 6 major hurricanes (Category 3, 4 or 5; winds of 111 mph or higher)
The lessons of this vulnerability were, perhaps, more than most years, evident in 2005. The first sign of problems came with the arrival of Hurricane Dennis in July. It was a storm which severely damaged the BP deep water Thunder Horse drilling platform.

Thunder Horse after Hurricane Dennis (Prof Goose)

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

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

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

Gulf of Mexico showing regional features (Geoexpro)

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

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

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

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

Technology was, however, allowing rigs to work in ever deeper water, 100 ft of water in 1957, 225 feet by 1965, and 300 ft in 1969. With this increase in range came increased production, which had reached 2 mbd, but it also exposed more rigs to the threat from larger storms. Hilda, formed in 1964, caused $100 million in damage and effectively destroyed 18 platforms,; Betsy in September 1965 had the distinction of financially impacting a future President of the United States.
On September 9th, the day Hurricane Betsy struck, MAVERICK was located 20 miles off the Louisiana Coast in 220 ft of water. The following day an inspection showed Zapata’s three other rigs were undamaged, but the MAVERICK had vanished. This was the largest single loss that the domestic offshore drilling industry sustained in this or any other hurricane. . . . . .The MAVERICK loss was a substantial one for Zapata. This was our newest rig and one of our very best contracts. . .
(George H.W. Bush, “My Life in Letters and Other Writings.”) (The insurance check was for $5.7 million).

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

Fortunately such storms have proved to be relatively rare, and the “three strikes” of Dennis, Katrina and Rita in 2005 have not been repeated since. Yet the industry remains highly vulnerable to such storms. As the second figure shows, the Gulf has become increasingly filled with production platforms. In 2008 this region was hit by hurricanes Gustav at the start of September and Ike two weeks later. Even though these were weaker storms their impact was significant.
Effective August 2008, there were more than 3,800 production platforms in the Gulf, ranging in size from single well caissons in 10 feet of water up to a large, complex facility in 7,000 feet of water. The MMS estimates about 2,127 production platforms were exposed to hurricane conditions from Gustav and Ike, carrying winds greater than 74 miles per hour.

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

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

The platforms designated as destroyed following Gustav and Ike produced 13,657 barrels of oil and 96,490,000 cubic feet of gas per day, or 1.05 percent of the oil and 1.3 percent of the gas produced daily.
Part of the reduction in damage came from lessons learned from Katrina/Rita.
Mobile Offshore Drilling Units (MODUs) that previously had to have eight mooring lines were now required to have 12 and, in some cases, 16 mooring lines,” Angelico said. “In ’08, 18 moored MODUs were in the path of hurricane force winds, and two went adrift, which represented 15 percent of the rigs out there. In Katrina and Rita, 63 percent of the rigs went adrift.’

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

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

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

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

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

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

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Posted by Heading Out at 11:14 PM 0 comments
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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.
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.

Any supply shortfall could prompt a surge in import demand as utilities and firms seek alternative fuel supplies to feed their power plants.
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.
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.

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.
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 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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Posted by Heading Out at 10:50 PM 7 comments
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Thursday, June 17, 2010

Deepwater Oil Spill - the BP CEO and Congress

There are many people who have questions for Tony Hayward, the CEO of BP. (For those behind the times, they changed their name from British Petroleum some 9 years ago) today was the turn of Congress. But before going to that testimony, the current status for things in the Gulf, as far as oil recovery from the Deepwater Horizon well oil spill is:
Optimization of the dual system, LMRP Cap and the Q4000 Direct Connect, will continue over the next few days.

For the first 12 hours on June 17 (midnight to noon), approximately 8,000 barrels of oil were collected and approximately 4,500 barrels of oil and 25.8 million cubic feet of natural gas were flared.

On June 16, a total of approximately 14,750 barrels of oil were collected and approximately 3,850 barrels of oil and 40 million cubic feet of natural gas were flared.
That means that oil recovery from the well, which is the usm of that collected and that flared is now reaching a level of 25,000 bd. The capacity of the current system is around 28,000 bd, beyond which they will need to wait for the change in vessels, risers and for the new cap now planned for the end of the month. This will mean that the Q4000 will be disconnected, and control of the valves at the BOP also transferred.

Although it is difficult to tell from the ROV feeds, it appeared earlier that the venting ports at the top of the LMRP cap might have been closed, so that BP are now much closer to capturing all the oil and gas leaking from the well. The feed from the Skandi ROV1 for example seems to have more gas in it than previously. Similarly at the time this was written the vertical feed into the DP at the top of the cap can be seen, from the Enterprise ROV2 feed.

ROV view of the LMRP cap June 17th 8:30 pm

There were five questions that Mr. Hayward was warned that he would be asked about, before he appeared before the House Energy and Commerce Subcommittee on Oversight and Investigations. However while the committee obviously focused on the events at the particular well (Mississippi Canyon 252 – the Macondo well ) which had the disastrous failure, they seemed to find it difficult to accept that, prior to the disaster, and with BP drilling hundreds of wells a year, the CEO’s only knowledge of the well had been that he had heard that it was a successful discovery. Congressman Waxman, for example, dwelt on the ignorance of BP top management about the well.
You are the CEO, so we considered the possibility that you may have delegated the oversight responsibility to someone else. We reviewed the e-mails and briefing documents received by Andy Inglis, the chief executive for exploration and production, and Doug Suttles, the chief operating officer for exploration and production and the person now leading BP’s response to the spill.

According to BP, these are the senior officials who were responsible for the Macondo well. But they too were apparently paying no attention. We could find no evidence that either of them received any e-mails or briefings about the Deepwater Horizon rig or the drilling activities at the well.
It was the Subcommittee Chair, Congressman Stupak who outlined the areas of concern that are being investigated:
We have learned that time and again BP officials had warning signs that this was – as one employee put it – “a nightmare well”. They made choices that set safety aside in exchange for cost cutting and time saving decisions. For example
 They disregarded questionable results from pressure tests after cementing in the well.
 BP selected the riskier of two options for their well design. They could have hung a liner from the lower end of the casing already in the well and install a “tieback” on top of the liner, which would have provided additional barriers to a release of hydrocarbons. Instead they lowered a full string of new casing, which took less time and cost less, but did not provide the same protection against escaping hydrocarbons.
 BP was warned by their cement contractor Halliburton that the well could have a “SEVERE gas flow problem” if BP lowered the final string of casing with only six centralizers instead of the 21 Halliburton recommended. BP rejected Halliburton’s advice to use additional centralizers and in an e-mail on April 16, a BP official involved in the decision explained: “it will take 10 hours to install them. ... I do not like this.”
 BP chose not to fully circulate the mud in the well from the bottom to the top, which was an industry recommended best practice that would have allowed them to test for gas in the mud.
 BP chose not to use a casing hanger lockdown sleeve, which would have provided extra protection against a blowout from below.
In his written response, Mr. Heyward first addressed the processes that BP are going through to address the current problems (cutting off the oil flow to the Gulf, cleaning it up and compensating those who have been damaged and economically impacted). He pointed to seven areas in which BP have focused their inquiries into the incident.
The investigation is focused on the following seven mechanisms:
1. The cement that seals the reservoir from the well;
2. The casing system, which seals the wellbore;
3. The pressure tests to confirm the well is sealed;
4. The execution of procedures to detect and control hydrocarbons in the well, including the use of the blowout preventer (BOP) and the maintenance of that BOP;
5. The BOP Emergency Disconnect System, which can be activated by pushing a button at multiple locations on the rig;
6. The automatic closure of the BOP after its connection is lost with the rig; and; 7. Features in the BOP to allow ROVs to close the BOP and thereby seal the well at the seabed after a blowout.
The video of the testimony is available from the Subcommittee website.

In his opening questions Congressman Waxman noted that the BP decision to use a single production casing was rebutted by the heads of the other large Oil Companies who had earlier testified before Congress. The reason being that it provided “”an unrestricted pathway for gas to travel up the well through the annular space that surrounded the casing, and of course, it blew out the seal.” Mr. Heyward pointed out that this was the original design for the well, and that it had been approved by the MMS. There was then a debate as to whether a long string, or a 7-inch liner would be most appropriate. The decision to use the long string was based in part on the long term integrity of the well.

Congressman Waxman pointed to a BP memo which included that the use of the long casing consequence would include that “it is unlikely to be a successful cement job, and that it would provide an open annulus to the wellhead.” In contrast the use of the 7-inch liner would largely obviate these risks.

When Mr Heyward tried to answer that the Congressman cut him off and accused him of stonewalling, refusing to accept that the decision was made based on an engineering judgment – which was the point that the CEO was trying to make. Mr Hayward tried to make the point that the long casing was not an unusual design in the Gulf of Mexico wells, to which the Congressman responded with Halliburton testimony that it was only used in 2 – 10% of the wells, and when My Hayward said that he would not personally judge which decision was correct, which the Congressman found unacceptable.

It was that sort of a day for the BP CEO and the full video of the investigative hearing can be downloaded, as I noted.

As the above exchange illustrated, there was not a lot of useful new information that came from the afternoon (though I must admit I had other things to do and did not watch most of it).

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Posted by Heading Out at 9:59 PM 3 comments
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Wednesday, June 16, 2010

Deepwater Oil Spill - the Presidential Speech

The secondary collection system, using the Q4000 has now been activated to help collect the growing volumes of oil generated from the oil spill at the Deepwater Horizon site in the Gulf of Mexico. There was also a small fire, yesterday, due to a lighting strike, that shut down collection for a short while. The current status is thus
For the last 12 hours on June 15th (noon to midnight), approximately 4,830 barrels of oil were collected and 14.6 million cubic feet of natural gas were flared.

• On June 15th, a total of approximately 10,440 barrels of oil were collected and 25.1 million cubic feet of natural gas were flared.

• Oil collection volumes were lower on June 15th due to the direct lightening strike on the Enterprise.

• Total oil collected since the LMRP Cap containment system was implemented is approximately 160,400 barrels.

• Collection commenced on the Q4000 at ~9:50pm with hydrocarbons reaching surface at ~1am on the 16th. We expect to optimize collection over the next few days.
The President has now given his Oval Office Address to the Nation on the Oil Spill, and I will update this as the news of his discussions with BP officials goes on. But the speech itself is worth examining. The most critical part of the spill is to get the leak stopped. It was the first significant topic of the speech, but this is what he said:
Because there has never been a leak this size at this depth, stopping it has tested the limits of human technology. That's why just after the rig sank, I assembled a team of our nation's best scientists and engineers to tackle this challenge -- a team led by Dr. Steven Chu, a Nobel Prize-winning physicist and our nation's Secretary of Energy. Scientists at our national labs and experts from academia and other oil companies have also provided ideas and advice.

As a result of these efforts, we've directed BP to mobilize additional equipment and technology. And in the coming weeks and days, these efforts should capture up to 90 percent of the oil leaking out of the well. This is until the company finishes drilling a relief well later in the summer that's expected to stop the leak completely.
So the recommendations of the “nation’s best” is “do better?” or “do more?” To which BP has responded by bringing in more collection equipment, but has not changed their current response to sealing the leak – which is basically to rely on the relief wells. (Although I did hear some stories that it was the “expert” team and Dr. Chu that told BP to stop the Top Kill attempts). But that was all the coverage that the most critical part of the speech provided.

The problem, of course, is that the problem is not solved until the leak is closed. Thus the “X days of the Gulf Crisis” that is the mantra of the main stream media will likely continue until X reaches about a hundred, and by then, barring some further catastrophe (and I’m not ruling one out) the public may be rather tired of the story. The clean-up is vital, dealing with the compensation for those who have lost wages will become interesting.

BP have just agreed to set up a fund of $20 billion to recompense those who have lost jobs and livelihoods. They have also suspended their dividend for the rest of this year. But the Administration gave BP some years to create the fund, so that the company does not get wiped out. They also agreed to create a $100 million fund for those in the oil patch who have lost work because of the moratorium on drilling.

It gets them off the hook, but I am very dubious that it will accelerate payments to individuals and companies. While BP had the responsibility they had to hire the accountants, clerks, and administrators to oversee the distribution. These folks had to have rules, which had to be written, and paperwork documentation of claims had to be established. Getting that done as fast as it was is something that private industry, with the right incentives, can largely achieve.

But if the whole process, or significant parts of it, have now to be redone with a different set of rules to be established, then BP can now claim no responsibility, and it will be the Administration which starts to get targeted as payments continue to be delayed.

Bureaucracies take time to build and once established hard to get around, and that is not going to be true just for those who need a check in the next week or so to pay the mortgage, or feed the kids. With apparently 14 different agencies involved in the clean-up getting all the permissions for particularly innovative approaches had already required some creative thinking, and may require much more if, for example, advanced skimming tools are to be used within meaningful time. Again, based on current performance I am becoming more cynical as to success, as the Administration claims more authority over what is, and is going to be done.

The other half of the speech dealt with the need to accelerate the change to alternate fuels. This is a site that is seriously concerned over the coming shortages of fossil fuels, and oil in particular. So encouraging the development of alternatives is something that needs to be done. Did it need to be in this speech? That is a political issue I don’t want to address. But there were not a lot of specifics in the speech. It was more along the lines of
Others wonder why the energy industry only spends a fraction of what the high-tech industry does on research and development -– and want to rapidly boost our investments in such research and development.
Well the federal agency that used to support such R&D was the U.S. Bureau of Mines, in the Department of Interior. It was one of the few agencies that the Federal Government (in the Clinton Administration) has ever closed. So maybe this isn’t just an industry problem?

So at the end of the day there are no specific new steps to move forward with. We will see what Congress brings forth.

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Posted by Heading Out at 2:23 PM 9 comments
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Monday, June 14, 2010

Deepwater Oil Spill - the new BP plans

BP has now sent a reply to Admiral Watson in regard to the Coast Guard request that BP provide a “better” plan for dealing with the oil spill at the Deepwater Horizon site. In part the response deals with increasing the capacity for the collection of oil through the provision of additional vessels, in part preparing better for a Hurricane, and in part providing better back-up systems.

This post will go through and explain what the letter describes, and I intend, in a later post, to explain in more detail why BP should plan for a steadily increasing volume of oil. Simplistically it is because the erosion from the sand in the oil continues to widen passages through the reservoir, the casing and lining of the well, and the BOP. The new "production" volumes have also been released.
For the last 12 hours on June 14th (noon to midnight), approximately 7,800 barrels of oil were collected and 16.8 million cubic feet of natural gas were flared.

• On June 14th, a total of approximately 15,420 barrels of oil were collected and 33.2 million cubic feet of natural gas were flared.

The first step in the new process begins almost immediately, and that is the redirection of oil, so that it flows up through the choke line of the BOP to the Q4000.

This is a reversal of the flow of mud that was used in the Top Kill option tried earlier. The system is being tested today, and if it all works, then by tomorrow (Tuesday the 15th) the oil and gas drawn off from the well, will flow up the 3-inch lines to the Q4000 where the oil will be vaporized and burned with the “Evergreen Burner.” Given that this will burn oil in the range from 5 – 13,000 barrels a day (at $75 a barrel) that is a lot of money (up to $1 million a day) going up in smoke that could have gone to relief – but that is becoming small change. However a single Burner can only burn 3,000 bd, so it would appear that a multiple mount is being built.

The Schlumberger Evergreen Burner

There are some concerns with this plan. Some of the “junk” pumped into the well might be flushed back out by the oil, into these smaller lines, and block them. The sand in the oil that is eroding the BOP and casing could also erode the choke and kill lines, which are vulnerable, particularly at the couplings and with the hose jumpers. Those concerns will continue until the more permanent risers are installed .

That should bring the capacity of the system up to 28,000 bd. But the continued erosion of the flow paths means that additional provisions should be on hand.

The first increase in capacity – Adding the Q4000 to the collection system

At the end of the month the more permanent riser (for which they just located the suction pile) will be in place. This will allow a more permanent sub-sea system to be installed that will be less vulnerable to Hurricanes. The riser will provide oil to either the Toisa Pisces, or the Helix Producer. This latter is a Floating Production Unit that is already in the Gulf, but working on the Phoenix field.
As a result of the HPI's involvement in the BP spill response, production from Helix ESG's Phoenix deepwater oil field will be deferred until the HPI comes off hire with BP. Helix ESG expects the financial contribution from the BP HPI contract will offset the financial impact from deferred production of the Phoenix oilfield. The Phoenix oil field, located in the Gulf of Mexico's Green Canyon block 237, is ready to commence production upon HPI's return to the site, with all necessary U.S. Coast Guard and Minerals Management Service permits and approvals in place.
However, the opportunity costs for this additional back-up are only going to become obvious in the longer term.

Step 2 – the second vessel arrives and is connected.

At this point in the process, with a capacity of 53,000 bbl a day there is still the concern that the well could be producing up to 100,000 bd, and so additional capacity is still required. This will come by now supplying an FPSO to the site. I had mentioned this last week at which time BP did not seem to think one was necessary. They have now changed their minds and a vessel (yet unidentified) will be released from South America to come to the Gulf. It will take 4-weeks to arrive, and is being brought, in part, to provide insurance in case the Toisa Pisces, or the Helix Producer should have a problem. This can handle some 25,000 bd. And will raise to overall capacity at the site to 80,000 bd.

However the flow paths will be changed, so that the primary vessels receiving oil are the Helix Producer and the Toisa Pisces, which can handle up to 50,000 bd, and the other vessels available (the Enterprise and the Clear Leader, which is a second drillship, – the Q4000 being possibly released) providing additional coverage.

Step 3. The additional flow and storage capacities by mid-July.

It is interesting to note the plans include that the new LMRP cap that will be installed will “ensure a successful relief well kill operation.”

As part of the transition the controls of the feed lines on the BOP, which currently pass through the yellow pod on it, must be transferred to one of the FPSO’s and to back this up, the engineers are now working to resurrect the blue pod on the BOP and make this available.

BP add some caveats to their current plans.

1. Changing the cap could cause problems.
2. It depends how good a seal the new cap gets as to how much oil will be collected.
3. The flow rate is not known, and so the plans are only contingent on the estimates.
4. Leaks will occur whenever the system has to change.
5. They can’t collect oil in the middle of a hurricane.

Now all we have to do is to see if President Obama leaves them with enough cash to pay for all this.

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Posted by Heading Out at 2:02 PM 3 comments
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Thursday, May 27, 2010

Deepwater Oil Spill - restarting the mud, and an apology

It appears that a significant part of what I have written for the past day has been wrong, and the information that I, in good faith, commented on to several radio stations and newspapers about the status of the Gulf leak was similarly not totally correct.

I have reaped, I guess, the rewards for believing statements about transparency. From the LA Times
The company announced late in the day that it had suspended shooting heavy drilling mud into the blown-out well 5,000 feet underwater around midnight Wednesday so it could bring in more materials. Thursday evening, BP PLC said it had resumed the pumping procedure known as a top kill. Officials said it could be late Friday or the weekend before the company knows if it has cut off the oil that has been flowing for five weeks.
The conclusions that I drew about the pressure drop up through UPDATE 8 on Wednesday, when we were losing visual contact with the leak, because of what I thought was mud falling around the well could have been correct.

However, later comments on the relative flow velocity were based in part on the assumption the BP was still pumping mud. They were not. So that while the velocity observation was correct (since BP has stopped pumping) that is the only consolation I have from believing the Admiral’s statement this morning that there was only a slight problem with pressure balance before the company could start pumping cement into the well. (The LA story that I took this from has been updated so I cannot go back to the original quote). As I say this is more than mildly irritating, and I will try and be more cautious in drawing conclusions in the future. It does, however, through the pictures I posted, allow us now to be able to identify the difference between the mud flow (top picture) and the oil/gas flows that are in the remainder, with very little, if any, mud. (and at 8:40 pm on Thursday it is still oil and gas).

There was, however, some additional material available in the article:
Although incident commander Adm. Thad Allen of the U.S. Coast Guard said Thursday morning that BP had temporarily stopped the flow of oil, the company's chief operating officer later said petroleum was still flowing. "Once the well has stopped flowing then we would pump cement down into the hole to fully seal it," Doug Suttles said. "We might finish this in the next 24 hours, or it might take longer." Engineers next plan to inject heavier "bridging material" above the mud to prepare to put a cement seal on the well.
Well I see that the monitoring ROV is back in position to watch the leaks as BP, perhaps, is about to restart pumping mud – if they really are.

I would stop commenting on this, but sadly it is too important a subject not to continue. My apologies if I have, inadvertently misled you.

UPDATE: 9:52 pm the camera is focusing on the cracks in the riser, and it seems that they may be injecting rubber pieces one of which is now stuck in one of the cracks in the riser. (Not very securely it seems)

Piece of "junk" (?) in the riser crack, as BP apparently work to reduce the size of the path through the BOP.

Note that this piece has had to pass through the BOP, and it is sealing the BOP path which is more critical to success. It could also be a piece of the rubber from the annulus seal that broke loose and got caught in the riser. Without knowledge of what BP is trying it is hard to decide, but the flow looks to be still gas and oil without mud, and I would expect that BP would have to use mud as the carrier if they were injecting material into the flow, so this could just be a piece of seal that got caught. If you can't tell where it is, it is in the crack to the immediate right of the center line (without the paint) on the riser. (The view has changed)

UPDATE 2: Mud is clearly visible in the change in the look of the flows out of the riser. But at the moment it does not appear to be under the pressure of the flows on Wednesday. (This could be because it is being pumped in at a lower pressure, or it could be that they have sealed some of the leaks in the BOP and that is cutting back the driving pressure at the riser).

Leak shot at 10:25 pm Central

The problem we saw on Wednesday night with mud being heavier than oil and thus settling more readily and obscuring the view, is also evident.

UPDATE 3: 12:18 AM So it appears that BP have injected "rubber strips" into the flow, and that some of these have lodged in the BOP, reducing the flow channel, while one made it through and is trapped in one of the leaks in the bent portion of the riser.

Now what may happen is that they will slowly increase the mud flow/pressure to a) find out how much the leak rate has been reduced and b) to make sure that the restrictions in the flow channel are stable, and won't blow out. (If they do then they will have to repeat the process). Once they have a sure reduction in leakage then they will re-generate the higher pressures that overcome the pressure in the reservoir and start forcing the oil and gas back down the well, as the mud begins to fill the pipe.

The mud seems to have a slightly different texture from last time, so they could have increased the mud weight so that when the column of mud is re-established that this time it weighs a little more and overcomes the slight pressure imbalance that they were left with the first time they tried this.

Now is a good time for caution and, though the fill time may be reduced because of the smaller leak rate into the Gulf, they may still pump at a relatively only slightly higher pressure that that in the reservoir, to slowly sweep down the well, getting into the necessary channels, and giving time for the oil and gas to be pressed back into the rock that it came from.

UPDATE 4: 9:30 AM The latest report from the Gulf
Hayward told CNN BP engineers had injected a "junk shot" of heavier blocking materials into the failed blowout preventer of the ruptured wellhead, and would also pump in more drilling "mud"- all part of the top kill procedure being attempted.

"We have some indications of partial bridging which is good news," he said.

"I think it's probably 48 hours before we have a conclusive view," he added.
Admiral Allen also noted at that time that the leak had been stopped, but that they were not sure that they could sustain the halt in flow. However at 8:10 am, Sterling925 who wa watching and commenting on The Oil Drum saw some sort of event occur around the BOP.
Chaotic images - looks like an explosion!

09:14 et 5/28/2010
and from SteinarN
It looks like A LOT of gas is coming up from the seabed around the BOP. Considering the large water pressure and the possibly large area this gas is emanating from it ought to be a large flow. This indicate the integrity of the well is not good?
Unfortunately I did not see any of this and haven't been able to see the BOP apart from one short short since, though in that shot it did not appear to have any problem. The PBS viewed ROV at the moment is working with a chain, while the ROV that was monitoring the plume is now staring out into the ocean.

The CNN shot however shows that we are back with oil and gas apparently coming out of the leaks at the top of the riser, and no different to the conditions before they started pumping mud into the well last evening. So the second filling of the well has apparently all been washed out, and they will try again later. The comment from BP was that this might take another couple of days.

UPDATE 5: 10:24 AM Well I am not sure that the CNN feed was actually live and there are other stories catching their attention at the moment, but there is a Youtube recording of what took place (h/t Jessica in Pensacola).

UPDATE 6: 11:09 AM The feed has gone back to the riser, and we are back to the oil and gas flows that we were saw at the beginning. Not quite the same shapes as earlier, so perhaps the block in the BOP was partially effective, but BP have now apparently filled the well twice and failed to get enough weight into the mud to hold the driving pressure from the rock. They could try again with a higher density mud, I am presuming that the second shot had a higher weight than the first, and that while the first left a small pressure imbalance, that the second was closer, but as yet no banana. (Though the Admiral did say that they had stabilized the flow). My presumption is that they will mix up another batch and try again - though whether they will try another junk shot is not clear.

Flow at 11:09 am

The way in which you try and stop leaks is that you put the big stuff in first. If you can get enough of that to stick, it still leaves large flow channels, and so the second shot uses smaller pieces that fit into the gaps. Then you try smaller shots etc until you get as good a seal as you can. Doing this to plug water flows into tunnels can take several shots to get a total seal, working with sequentially smaller sizes of particles.

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Posted by Heading Out at 8:48 PM 4 comments
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