Tech Talk - Of production stability, peaks and the future

Jeffrey Brown (Westexas from TOD) is quoted extensively in Kurt Cobb’s recent piece that points out that global crude production has pretty reasonably stayed constant at between 64 and 67 mbd since 2005. (H/t Nate Hagens). While there has been a total increase in the total refined products side of the house (with the total number floating around 90 mbd) this includes a number of different sources that, within generally defined standards, are not considered crude. The four main culprits that he lists are biofuels, natural gas plant liquids (NGLs), lease condensate and refinery gains. He makes a good point.

Figure 1. Crude oil production alone over the past decade (Kurt Cobb)

I can remember that it was some years ago, when looking at the OPEC reports on production, that I suddenly realized that the projected increases in NGL production made a significant difference in the overall volumes that they were producing. (It is anticipated to average 5.95 mbd in 2014). Back in 2001 OPEC just defined the fluid as natural gas liquids, but went through significant revisions of numbers in 2002 and in March 2004 redefined the volume counted as “OPEC natural gas liquids and non-conventional oils”.

Figure 2. NGL and unconventional oil production by OPEC (OPEC MOMR )

Over the past decade volumes have almost doubled. In the United States, with the increased development of the shale gases, production has also increased.

Figure 3. Increase in production of NGL in the United States (EIA )

The price obtained for these fluids, however, falls below that of conventional gasoline. For example:

Figure 4. Relative prices of NGL fuels relative to crude and gasoline. (EIA)

The EIA is reporting a continued growth in US production:

Altogether, in the Bakken, Niobrara, Permian, and Eagle Ford, oil production is expected to increase by 70,000 bbl/d in May 2014. The monthly growth rate is 3,000 bbl/d more than in April 2014 due to solid gains in Permian rig count and continuous rig productivity gains across the regions. While the DPR does not forecast weather impact, the spring thaw season has officially started in the Bakken region and may disrupt some drilling activity between now and June.

These additional resources take on an increasing importance as world demand is anticipated to increase another 1.14 mbd this year, slightly up on this year’s figure. This gain in demand was largely offset by increased production from the Americas, though OPEC note that overall global suppliy decreased last month to average 90.63 mbd but is expected to reach peak demand in the fall, at 92.24 mbd.

Looking at the supply side for this year, and bearing in mind that gains must more than offset lost production if the total increase in supply OPEC are projecting an overall gain in supply of 1.34 mbd, largely to come from outside of OPEC. This is expected to come from the OECD Americas (the USA, Canada and Mexico) group, while the increased production from countries such as those of the Former Soviet Union is expected, to rise by 150 kbd or less.

There has been relatively little change in the estimates of where the increases in North American production are anticipated to come. By the end of the year US production is expected to reach 12.45 mbd by the last quarter of the year. As OPEC noted:

Based on the US Energy Information Administration (EIA)’s monthly oil production report for January, regular crude oil output registered at 4.93 mb/d, tight oil production increased to 3 mb/d, NGLs output reached 2.64 mb/d and biofuels and other non- conventional oils recorded the highest output at 1.22 mb/d. The use of energy from biomass resources in the United States grew by more than 60% over the decade between 2002 and 2013 — primarily through increased use of biofuels like ethanol and biodiesel which are produced from biomass. According to the EIA, biomass accounted for about half of all renewable energy consumed in 2013 and 5% of total US energy consumed.

This month the OPEC MOMR focused on increased production from the Gulf of Mexico, with anticipated gains from the Olympus project at Mars B.

The total gain in production from the Gulf is currently anticipated to increase, this year alone, to perhaps 1.55 mbd, and to pass the previous record Gulf production of 1.8 mbd by 2016. In addition the Cardamom project is expected to add 50 kbd to the Olympus figure, and the start of oil production from Phase 3 of the Na Kika field is expected to add an additional 40 kbd to the 130 kbd which Na Kika is currently producing. However Gulf wells have a habit of going south a little earlier than predicted and I have borrowed the following graph from Ron Patterson which illustrates the cumulative fate of the combined Atlantis, Thunder Horse, Tahiti and Blind Faith fields.

Figure 5. Changes in production from major Gulf of Mexico fields over time (Ron Patterson )

When this is combined with Dennis Coyle’s prediction that the Eagle Ford field will peak in 2015, at 1.4 mbd, with a declining rate of production increase as one reaches that peak. Similarly the number of wells that can continue to be drilled in North Dakota in the sweeter counties of the state are limited, and beyond that there is a concern (which I have expressed before, and which others have explained much better than I) that as the estimates of production fall in the less successful regions of the state that it will become harder to raise the capital for the new wells needed to sustain and increase production.

That being said, I am beginning to suspect that this may be the year that the OPEC estimates for US production may get a bit ahead of what actually is produced. And if that is the case, then that means that the following two years will become even more interesting as the nations of the world start to realize that yes, there is a peak. Which might mean that the coal resurrection might be greater than I currently anticipate, but perhaps I will have more on that next time.

Hurricane ISAAC and the Gulf Coast

The political world is waiting patiently for Tuesday, when the Republican National Convention is officially getting under way, after a postponement due to the nearby passage of what remains Tropical Storm ISAAC. The question that begins to arise, however, is as to whether the political news will be swamped by the consequences of ISAAC’s arrival.

Figure 1. The current prediction for the path of Tropical Storm ISAAC, as it skirts Florida, on its way to the Gulf Coast.(National Hurricane Center)

It has been some 7 years ago that the three hurricanes of 2005, DENNIS, KATRINA and RITA, did a number on Gulf oil production. We have, in the interim, perhaps become a little complacent about the impact of a major hurricane on Gulf oil production. It was DENNIS which did such damage to the Thunder Horse platform back in July of 2005, that it took several years to bring it back into operation. (video here ). DENNIS shut in some 1 mbd, but for only a short time.

Figure 2. The Thunder Horse platform after Hurricane DENNIS in July of 2005. (Youtube )

However it was followed by KATRINA and RITA, so that, between the three of them they covered not only the swath of the ocean that included most of the drilling platforms in the Gulf, but also, as they moved inland, a significant number of the refineries on which the nation has come to depend.

In the seven years since then, the lack of significant hurricane impact on the Continental United States has led to some complacency as to the vulnerability of the country to the hurricanes that have, from time immemorial, threatened these shores.

But it is worth just a quick reminder that the impact is not just seen in damage on shore, grievous though that may become. (I was on a survey team that was one of the early groups that went down the delta after KATRINA). Already platforms are being secured:

The Bureau of Safety and Environmental Enforcement says 39 production platforms and eight drilling rigs have been evacuated as of Sunday. That's about 6.5 percent of the 596 manned platforms and 10.5 percent of the 76 rigs operating in the Gulf of Mexico. . . . . . . The bureau says operators estimate that about 24 percent of the current daily oil production and 8 percent of natural gas production has been cut off.

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The paths of the storms are somewhat different. KATRINA came in more directly from the south:

Figure 3. Path of KATRINA in 2005 (Central Florida Hurricane Center).

The path of ISAAC is currently anticipated to be more direct, as shown in Figure 1, but there are several things to bear in mind, as we move into this week.

Figure 4. Platforms along the Gulf of Mexico (FOX 4)

Firstly it was not only the platforms themselves that caused the problems in the United States after the hurricane season of 2005. There are a lot of refineries around the NOLA area that were damaged at the time, and which have not moved since.

Figure 5. Refineries around New Orleans in the region of the KATRINA hurricane track.

Hopefully between then and now the relevant refinery will have got all the switchgear that gave them problems back then out of the basement and into a less flood-threatened location.

As far as the people that live in the region are concerned, there are two additional worries. The first is that there is some thought that the hurricane may strengthen beyond a level 2, and KATRINA was only at a level 3 when it hit in 2005. The second is the direction in which the storm is approaching. While KATRINA had the full length of the delta over which to lose power, if ISAAC swings in from the East then it will pose a greater threat to the levees because it will impact Lake Ponchartrain.

If the storm tracks west of New Orleans, a storm surge into Lake Ponchartrain could push water against the city’s still-fragile levee system. If the storm makes landfall east of New Orleans, northerly winds on the west side of the storm could still create wave and water problems for the Crescent City. A landfall east of New Orleans could also bring a devastating storm surge onto the Alabama-MIssissippi coast.

. As a precaution rigs and platforms have been put into a protective posture, which has reduced daily oil production by 24% and natural gas production by 8%.

Until the full nature of the threat develops, however, it is thought that the refinery fire in Venezuela may have greater impact, although it is being reported that the damage there was constrained to just two storage tanks. (Not that this is as big a concern to the United States as it used to be:

In the first five months of 2012, the United States imported just over 50,000 bpd of fuel from Venezuela, down from nearly 290,000 bpd in 2005, according to data from the U.S. Energy Information Administration.

And for the people of New Orleans and particularly those in the ninth ward, I hope that this time they have not dredged next to the levees, nor have they left any of the barges less than totally secured.

And, lest the Democratic Party start to feel too superior, there are rumors of another Tropical Depression that might make it more interesting in Charlotte, in early September.

OGPSS - A recap with some updates on North American production

This series of posts has just completed a review of the different regions of Russian oil production, with the conclusion that while Russia may maintain current production levels of around 10.4 mbd for a short while, it faces rising domestic consumption levels at the same time that it is not replacing existing production at a fast enough rate to be able to sustain exports. Without more investment than is likely available, the rate of new field development (given the harsh and remote nature of the sites) means that there will be a slow decline in available oil to the market starting fairly soon. (Given the large supplies of natural gas that are coming available, this series is going to focus a bit more on oil as we continue the review).

As the series continues, and moves slightly down the list to consider the future of the oil and gas fields in Saudi Arabia, it is worth noting that while there is little that Russia can do to significantly raise production in the short term, that does not hold for the desert kingdom. However, before moving on to KSA in detail, this week is a pause to consider some contextual changes in the overall picture.

One of the questions that has been raised many times relates to the reality of the true maximum production levels that Saudi Arabia can achieve. As oil prices have continued to rise politicians are calling for the Saudi’s to increase oil production, so that the price may fall. (This is a rather odd and unrealistic request when the KSA needs all the income it can get to help domestically.) The EIA, in considering the global oil flow as sanctions begin to bite on Iran have projected that OPEC has a spare capacity of 2.5 mbd, most of which comes from KSA. At present the KSA is producing at around 9.7 mbd up some 600 kbd from this time last year, according to the EIA, although there is a little question as to how accurate that number is. (The IEA is reportedly saying that KSA is already producing at 11.5 mbd.. However the IEA counts all liquids, as Gail has pointed out, while EIA values are for the crude and condensate, which add up to 9.7 mbd, so that while there appears a discrepancy there really is not). The debate is likely to see some harder numbers in the months ahead. Iran is already having problems marketing their oil, since after January 23rd the European Mutual Protection and Indemnity Club is no longer covering shipping contracts. This is making it difficult for consumers such as India to maintain supply, and they are already considering the use of sovereign guarantees for its shipping lines. At the same time the EU is not calling for coverage to be phased out until July 1.

The EIA report notes that Iran is currently the 5th largest producer of liquid fuels at 4.1 mbd, although it consumes 1.8 mbd of that internally. Thus the threat to the global market runs at around a 2.3 mbd reduction on current overall demand of around 88.1 mbd. The series will discuss Iranian production, and its prospects somewhat later, but before getting into an analysis of Saudi Arabia, it might be worth just a quick glance back at a couple of countries that have been covered earlier.

Estimates of future production are only that, and, as has been noted in comments on recent posts, not all anticipated production or plans work out as anticipated. To give but a few examples pointed out in comments, and elsewhere:

The Russian oilfield at Yuzhnoye Khylchuyu was initially estimated to hold 505 million barrels of oil, but has now been reported as only having reserves of 142 mb.. (Noted by voiceinyourhead) On the other hand the Sarmatskoye field in the Caspian is now considered to have double the original estimate, and is estimated as just under 1 billion barrels of oil equivalent in natural gas and condensate. It is anticipated to come on stream in 2016. And, while on the topic of natural gas, both toolpush and RayRay have noted that the natural gas from Sakhalin Island is not going to see the 3rd LNG train that I mentioned in the post on that topic, and that the natural gas will instead feed into a pipeline to the mainland.

In regard to the posts that were written to cover the United States and Canada, the February monthly flow of oil through the Alaskan pipeline has fallen to an average of 609,805 bd. This is down from an average of 624,716 bd in January and gets the flow closer to the point where solidifying wax and water start to cause problems.

In the time since the posts were written on North American production and promise (politically including Canada with the United States makes the overall change in production figures look better than if the figures were based solely on US production, particularly as oil from the Albertan oil sands rises to production levels of 3 mbd by 2015) the Canadian National Energy Board (NEB) released their “Canada’s Energy Future: Energy Supply and Projections to 2035” report. In seeking to predict future production the NEB anticipated that the price of a barrel of oil would rise relatively modestly over the next 20-years. Even in their high estimate they do not see the price rising to more than $160 a barrel by 2035 (who would bet that the estimate is exceeded this year or next?).

Canadian estimate of the future of crude oil prices (NEB )

The report estimates that in the Reference case, oil production from the oil sands will reach 5.1 mbd in 2035, which is three times 2010 production. This will be mainly from in-situ methods.

Canadian crude oil production (NEB )

Over the ten years from 2010 to 2020 in-situ production is anticipated to grow at 9% p.a., while mining production will rise at 5% p.a. The North West Upgrader is anticipated to come on stream in 2014, with an initial 50 kbd of throughput. Carbon dioxide produced during the process will be used in Enhanced Oil Recovery (EOR) locally. If the price rises to the highest levels anticipated, then production might be estimated to rise to just under 7 mbd in total for Canada by 2035.

Canadian production for different case estimates of price, as above (NEB

However the NEB do recognize that domestic consumption will affect overall supply, but consider that it will likely only significantly impact the lighter crudes, and that the difference between the roughly 4 mbd of heavy crude produced and the 3.8 mbd available for export in 2035 will reflect a relatively constant 0.2 mbd of internal consumption.

Canadian light oil future predictions (NEB

With considerably more oil, therefore, being available from Canada, albeit there remain concerns over how much will be shipped to the USA, there is somewhat less pressure on domestic producers. Which is likely good news since the likelihood of US production remaining at current levels is still doubtful.

One of the hopes for the future comes from the wells being drilled in the Gulf of Mexico, with DoE projecting that gulf production will rise to some 2 mbd by 2020, from 1.3 mbd at present.

One concern that remains however, lies in the actual levels of production that will be achieved. As Jean Laherrère has noted the wells in the deep water have not all held up their promise, peaking on average within a year of coming on line. Jean notes that the production decline with the Mars and Ursa fields are at about 9% per year, which he notes is less than half the decline rate at Thunder Horse. Darwinian is also tracking production, and although he notes that Tahiti is performing relatively consistently at 110 kbd, Atlantis is not coming close to the 185 kbd projected.

Atlantis production (Darwinian )

Exploration and development in the Gulf are, apparently now back to pre-Deepwater Horizon levels, one can only hope that future developments will be less dramatic and more successful.

The speed of that recovery is encouraging, though the results to date have been a little less promising than anticipated. But, as with operations in the Arctic, investment costs are going to be high for any new finds that are viable, and will take a number of years to develop, at a time when demand is going to continue to increase. The Gulf discoveries, for example, will likely start to come ashore about the time that the Bakken and Eagle Ford plays start to fall in production, and thus, overall, may not give the boost to American volumes that are currently being projected.

OGPSS - Deepwater Gulf and the presence of salt

The deep waters of the world’s oceans and seas are a frequent topic in discussions of the source of future production of oil. Having talked about the development of the offshore Gulf of Mexico oil and gas fields last time, in this post, I’m going to venture further away from the coast, and look at the deeper wells that are now where the most promising discoveries and developments are made. For the sake of reference, the U.S. Government has defined deepwater as being anything deeper than 1,000 ft. IHS (CERA) has defined it more recently as deeper than 2,000 ft, and in their projections last year had suggested that deepwater fields had the potential to contribute up to 10 mbd to global supply by 2015. This would be up from 1.5 mbd in 2000, and 5 mbd in 2009. And that would, as a “region” put it at the top of the league, in the company of Russia and Saudi Arabia.

Within the United States deepwater production is currently focused in the Gulf of Mexico (GOM) with individual oil fields that compete with state production.

Production from the Gulf Of Mexico comparing some individual platform production. ( Petro Views)

At present (August 2011) there are 27 rigs active in the Deepwater, in water depths ranging from 9,627 ft (Tobago) to one allowed in at 922 ft (GC 50). Eight of the rigs are being run for Shell. In total there are about 90 prospects being considered, while 81% of current GOM production of oil and 47% of natural gas comes from the deep waters of the Gulf.

For the three largest fields cited in the plot, Tahiti, is believed to hold 4-500 million barrels of oil (mb) started production in 2009 in 4,000 ft of water. Production is nominally some 125 kbd of oil and 70 mcf of natural gas. Atlantis lies under 7,100 ft of water and was set to nominally produce 200 kbd of oil and 180 mcf of natural gas. Thunder Horse lies in 6,050 ft of water, and even with delays due to having to do some re-engineering, is still not performing up to the anticipated 250 kbd of oil, and appears to be declining in production at a higher than expected rate. And even when the North field has been added, as Darwinian has noted, production has not been sustained at target levels.

These fields are now generating new projects that lie close to the original discoveries, Thunder Hawk, for example, lies close to Thunder Horse, and is in 5,724 ft of water with total vertical depth (TVD) of the well being 25,885 ft. It is designed for 60 kbd of oil, and 70 mcf of natural gas. Further discoveries continue to be made. In June, for example, Exxon announced a discovery in Keathley Canyon, so that even if the original potential is not achieved (and I have not even discussed fields such as Jack, which has been rated at perhaps 500 mboe) there will continue to be sustained production from the Gulf, even if it is steadily moving further offshore.

This might be a good point to slip in a little comment about salt domes. When the original Spindletop well was drilled in Texas, it was not recognized at the time that the hill from which the well descended had been formed by a salt dome. Yet once this had been grasped, the slight hills that were the surface feature of these domes became a guiding marker for wildcatting across Texas.

John Bratton has provided a little explanation of the initial history of salt in the Gulf. Simplistically, as the global pull separated North from South America it first created a valley :

The tearing apart of plates does not make an ocean right away. Usually, the big valleys first start to fill as salt deposits form, like those found in the Dead Sea in Israel and Jordan, or the Salton Sea in California. These deposits are called the Louann Salt in the area of the Gulf of Mexico. As the big crack at the bottom of North America widened, the ocean filled the big valley permanently, new ocean crust began to form, sediment began washing into the widening hole from the Mississippi, and other rivers and reefs grew along the shore, burying a width of more than 500 km of salt and the edges of the new crust.

Over millions of years, plumes of the light salt began to float up through the heavier sediment that covered it, like the colored liquid in a lava lamp. As the salt made it very close to the surface, sometimes having traveled through more than 10 km of rock and sediment, it pushed up the sea floor above it to form a mound or dome.

The driving force for the movement of the salt lies in the difference in specific gravity between the 2.19 SG of the salt, and the typical 2.7 SG of the overlying sediments. As a result, due to the plasticity of the salt, it will flow under the differential pressure and due to its lighter density preferentially deform upwards. ( This can be illustrated, for example, at the Wieliczka salt mine in Poland where miners have mined what they thought was virgin salt, only to find old mining equipment buried within the rock.) With time that upward movement pushed through and compresses overlying sediments.

Michel Halbouty has described how the Gulf salt, which can now lie some 30,000 ft below the surface, could then create the traps for oil.

Once the movement of salt begins, the forces of buoyancy are constantly at work, depending on the static weight of the sediments above the salt and on the flanks of the salt core. The main motive force of the uplift of the salt through the sediments is the static weight of these sediments, principally on the flanks of the salt core. The salt stock moves in stages through geologic time, depending on the thickness and the weight of the sediments above and around the salt mass. . . . . .
Cycle after cycle of this procedure took place until the domes gradually pierced their way through the overlying beds to their present positions under the surface of the earth . . . . . . .Some of these moved upward rather slowly, so that they could not keep pace with the rapid deposition of sediments and eventually became buried beneath many thousands of feet of overburden. These domes are referred to as "deep-seated," and gas and oil production is generally found in the arched, but unpierced, formations lying over the super-dome area. Other salt stocks, including the one at Spindletop, seem to have developed under conditions that resulted in the salt stocks remaining near the surface throughout their growth history. . . . . Gas and oil production at these domes is therefore likely to be important in the pierced formations that butt against the sides of the salt mass. It was one of these salt cores that finally settled under an area that is known as Spindletop.

It is difficult to see these deeply buried domes given the current geology of the undersea Gulf surface.

Gulf topography (Gulf Blue Plague)

Rather we have to rely on geophysical surveys where the subsea geology is plotted through the return of sound waves, allowing the rocks under the sea to be mapped in three dimensions. Using this technique it is easy to see (even in a simpler 2-D version) the presence of salt domes.

Salt migration and the effect on overlying Miocene deposits in the Gulf (after Morris via Geoexpro ) The image has been colored to enhance the features.

Similar structures extend to the East and are projected to be potential areas for future production closer to Florida. The salt does not, however, just move vertically upwards, but can also flow laterally. However, in earlier times the formations under the salt would not have been distinguishable because of the way that sound waves move through that rock. (The results have been compared with seeing through frosted glass). Thus hydrocarbons in beds below the salt would have been hidden.

Hydrocarbon reservoir that used to be hidden by overlying salt (BOEMRE )

More modern and advanced techniques have allowed formations to be seen both above and below the salt. (Or pre and post salt).

Depth section across the Florida Escarpment showing plays both above and below the salt Section width is 90 km, vertical magnification is 5:1 (Geoexpro)

As with the technology to find these deeper reservoirs so increasingly more complex drilling rigs have had to be developed to reach and develop the deposits. This included technology to drill through the salt, first carried out by Diamond Shamrock in 1983, although it was not until the Mahogany field was discovered by Philips Petroleum that commercial subsalt production began, Both Atlantis and Thunder Horse reservoirs lie sub salt.

Not all the equipment works as anticipated, and this has been evident, not only with the Deepwater Horizon tragedy last year, but in other rigs and other locations.

Hopefully now, however, the industry has learned the lessons that needed to be learned, and the permitting of new drilling means that the new discoveries that continue to be made can be developed without further loss of life.

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.

Drilling Rigs and Drilling Ships

The debate about how much oil is left and recoverable in the world has brought increasing attention to the recovery of oil and natural gas from offshore. And while I suspect that most of those who comment on this site are very familiar with all the terms, some of the more general readership may not be. Let me, therefore, explain just a bit about some of the different words that are being used here - with references and videos, where I can find them - to pictures of the different types of structures that are being used. And if I miss some, please chip in either to ask or answer.

Just as on land, we need some form of drilling rig if we are going to drive a bit down through the rock and find us some oil. But, unless we are working somewhere like the North Slope where we can wait until the sea freezes over and drive ice roads out to build islands to drill from, we are going to have to find a different way of providing the infrastructure support for that bit. And here is the first distinction - because a drilling rig, in the offshore sense, is more of an exploratory tool, going out to find oil, rather that developing the known fields and bringing in production. That latter task is left more to production platforms, which can be sited where best to drain the field, and may not even use the initial holes drilled by the exploration rig.

As you may have read the Minerals Management Service keeps track of production offshore (as well as on Indian lands) and lest you think that it is not that significant a bunch of folks, they have just handed out $10.68 billion in 2009.

Of the $10.68 billion, $1.99 billion was disbursed directly to states and eligible political subdivisions such as counties and parishes. Another $5.74 billion was disbursed to the U.S. Treasury; $449 million was disbursed to 34 American Indian Tribes and 30,000 individual American Indian mineral owners; $1.45 billion was contributed to the Reclamation Fund for water projects; and $899 million went to the Land & Water Conservation Fund, along with $150 million to the Historic Preservation Fund.

As with many departments of the Administration the MMS is focusing on

the importance of renewable energy and job creation, climate impact and adaptation, and efforts to support and maintain the treasured landscapes of America in the emerging clean energy economy.

Since it also controls (for the Secretary of the Interior) lease sales – with a large upcoming one in the Gulf it is a good site to check on periodically. Now to get back to what we’re going to do to get the oil/gas out if we are fortunate enough to get one of those leases.

In really shallow water, or the bayous, you might launch your bit from a drilling barge, where the derrick can be assembled once the barge has been towed to the right place. Barges can be flooded to rest on the seabed in relatively shallow operations.

Drilling barge

However they are very susceptible to bad weather, and last April one had to be raised after being sunk during Hurricane Gustav.

Raising a sunken drilling barge

So, as one moves further offshore, then one might use a self-erecting tender from a barge, but would more likely move to something which could get the drilling floor stabilized and up above the waves. These are the jack-up rigs.

Model of a jack-up rock (Stavanger Oil Museum)

Typically they have three legs, that are raised as the rig moves around. Then when it has reached the desired site, the legs are lowered to rest on the sea floor and the entire structure jacks itself up out of the sea, and, hopefully, above the waves. (You can get a paper model to cut out and assemble for this rig). There is also an animated video showing the installation of a rig at a site.

They can do this to work in depths to around 500 ft. The discussion about damaged rigs gave links to the different rigs that have been damaged, and some of these have photos of the rigs in better days.

As one goes out to deeper depths, then one will look for a more substantial vessel and so one comes to the Semi-submersible.

Semi-submersible drilling rig (Stavenger Oil Museum)

These are built to either sail themselves, or to be towed out to the site, with the assembly floating, and then fluid is pumped into the bottom tanks to partially submerge the vessel and thus stabilize it. One can get some idea of the size of these from some of the photos shown where, (thanks to Ed Ames), wikipedia covers the subject.

Semi-submersible rig off Brazil (Wikipedia)

Since these are floating there has to be a way of holding them in place. One way is to have them dynamically positioned, using thrusters to hold them in position, such as these.

Thrusters that go under the pontoons to stabilize a semi-submersible (Wartsila)

Note that it takes about 3 years to build such a unit. The alternative is to have the rig attached to anchors on the sea bed using cables, or tethers. (And for those interested in natural gas production, note that the same rigs are used for both).

Cables with controlled winches to stabilize a semi-submersible rig (Stavanger Oil Museum)

The connection between the well and the platform now becomes more flexible and special connecting pipes called risers are designed to reach from the blow-out preventer (BOP) at the top of the well, but on the seabed, and the platform. These must allow the rig to rise and fall with the tides and so models of behavior have to be written to design ways of allowing this.

An alternative is to use a drillship to do the exploration. The drillship has the rig mounted in the middle of the ship, and can thus move around somewhat more easily than the others. It is generally held in position by dynamic positioning while drilling. (Video here).

Drill ship (Stavanger Oil Museum)

Once the field has been established, then a larger production platform can be brought out and placed where it can, using directional drilling, reach the best places to extract oil from the field. It is these large structures, such as that the Orlan platform from which Sakhalin Island oil finally began to flow recently, or the Thunder Horse, or Mars platforms. Although the former was due to produce by 2005, it was delayed by damage from Dennis and did not get up into major production until the end of last year, while the Mars platform was extensively damaged by Katrina. it is now back in production.

One of the problems with using these large platforms for Deepwater recovery is that they focus collection and so when these two are disabled, for example, they take about 400,000 bd out of production. And once they are damaged they are not so easily replaced. Back when I first wrote on this subject, in 2005 demand for rigs so strong that, as the International Herald Tribune reported

"If a customer comes today with an order, he'll have to wait until 2009 for delivery," Choo said in an interview last week. "That's how busy we are. If he's willing to pay more, he can get a rig by 2008 from our American shipyard."

By 2008 demand was such that prices had risen to half a billion dollars for a drill ship.

The original article noted that while it may only take 2 years to build a rig, the yard could only work on 8 at a time, and thus current deliveries were for 2009. The more recent story notes:

As a result, drilling costs for some of the newest deepwater rigs in the Gulf of Mexico — the nation’s top source of domestic oil and natural gas supplies — have reached about $600,000 a day, compared with $150,000 a day in 2002.

These record prices have spurred a new wave of drill-ship construction. This boom could lead to renewed offshore oil exploration that would eventually bring more supplies to the oil market, and push down prices.

Already, 16 new drill-ships are scheduled to be delivered to oil companies this year — more than double the number delivered over the last six years combined. In fact, 75 ultra-deepwater rigs should be delivered from 2008 to 2011, according to ODS-Petrodata, a firm that tracks drilling rigs.

The Chinese have also introduced a new design which is circular.

The Sevan Driller is the world’s first of its kind, with the most advanced deep-water drilling capabilities that allow it to drill wells of up to almost 13,500 metres (40,000 feet) in water depths of up to nearly 4,200 metres (12,500 feet) and an internal storage capacity of up to 150,000 barrels of oil.

The owner is Sevan Marine. The construction of this rig started at COSCO Nantong Shipyard in May 2007 and was relocated to COSCO’s Qidong Shipyard in April for derrick erection and final commissioning activities. The rig is due for delivery in the third quarter of this year and will be deployed by Petrobras in the Santos Basin, off the Brazilian coastline.

As of last week it was on its way to Brazil (which takes about 75 – 80 days) where it will drill in the Campos Basin in just over a mile of water.

Again this is a very, very brief and simplified look at some of the ways oil and gas can be produced from under the sea. It barely touches on some of the difficulties that are encountered, however. The sinking of the one barge shown at the top of the post could have been also repeated with pictures of other rigs in storms, and in battered condition.