The facts are given below. Oil productiion in the Gulf is dwarfed by onshore production in TX, CA and the rest of the US not to mention that the US imports 60-70% of our crude oil wiht the largest supplier being Canada and the second largest being Mexico. Bad news is that reserves are declining everywhere including Gulf, Canada, Mexico, landside US and Middle East. Whether it is national security, carbon pollution in the air or the ocean or crude oil pollution in our oceans, wetlands and beaches that turns you on, the time to change our energy portfolio is now. Bottomline is that "we got to have energy" but we dont "got to have oil". Oil is a decling resource unlike the sun and solar byproducts like biomass which are virtually infinite, can be homegrown and would benefit Mississippi and Mississippi landowners enornously. I cant wait to hear your rationalizations, justifications, lies and propaganda, excuses and other BS about "Drill Baby Drill" and "What is good for big oil is good for America". Fact is that oil money- like other special interest money- has created a system of legalized bribery that is destroying America. It's all connected fellas whether you want to accept the truth or not. Incidentally, this missive does not signal my return to MS Ducks in any substantative way but I thought it was time to give yall a piece of my mind in light of the events of this summer. I dont own any real estate on the Gulf coast but if I did, I would be particularly interested in your defense of deepwater drilling in light of the loss of my property value. $20BB will be a drop in the bucket compared to the ultimate damages this mess causes. Choose your words carefully- you never know when the oil might get picked up in a hurricane and blown onto your house.
EXHIBIT A: AP article on BP blowout
In a report for BP dated April 18, two days before the explosion, Halliburton said its computer analysis revealed a "SEVERE gas flow problem" could result if BP used only seven centralizers — devices to keep the pipe centered — instead of the 21 Halliburton recommended. BP used six.
EXHIBIT B: June 11, 2010 Letter to Editor, Wall Street Journal
In response to Tony Hayward's June 4 op-ed "What BP Is Doing about the Gulf Gusher": It is time that the publicity spin that BP is putting on this disaster is put into perspective. What is alarming about the content of the article is not so much what it says, but what it does not say.
Mr. Haywood, chief executive officer of British Petroleum, asks, "How could this happen?" The answer has largely to do with BP's inability to follow its existing well-construction policies and those of the industry generally. The BP testimony to the House Committee on Energy and Commerce on May 25 says it all, but perhaps that material needs to be explained. From looking at that evidence, this is what we know:
1) When cementing the production casing the cementing crew, which was being supervised by BP, had difficulty landing the top plug into the casing shoe. This was the first "red flag" because a satisfactory cement job to the production string is fundamental to the safe operation on a go forward basis. The fact that the cement job did not go as planned should have caused the testing operation that followed to be carefully scrutinized, it clearly was not.
2) As is normal practice, the integrity of the pressure tight seal was tested by pressuring up on the casing and observing the pressure response. If pressure bleeds off there is clearly a problem with the pressure integrity of the shoe, However, industry practice dictates that a positive test, that is no pressure drop, is not diagnostic, simply because the reservoir pressure is sufficient to retain the pressure being applied. A negative test is useful because it is diagnostic of a failed cement job. In this case the test was positive.
3) Again, as is normal industry practice a negative pressure test was run, with pressure released from inside the casing and the pressure response was measured. In this case evidence has been bought before the committee that there was a 1,400 psi pressure response. This response is highly diagnostic and is therefore the second "red flag" and at this point the BP supervisors should have concluded that they had what the industry calls a "wet shoe." That is that the cement job had failed to form a seal at the casing around the reservoir which we know contains high pressure oil and gas.
4) At this point a decision should have been made to do a remedial cement job; this is an expensive operation, but having seen a 1,400 psi response, there was no choice.
5) The BP engineers then proceeded with the balance of the operation to temporarily abandon the well. This meant replacing the 14-pound-per-gallon mud that was in the wellbore with 8.5-pound-per-gallon sea water. The denser mud had been, up until this time, the primary pressure control and was keeping the hydrocarbons in place despite the lack of an adequate cement job at the casing shoe.
Given the two red flags that had been thrown up previously, one would have expected that as a precaution a cement plug would have been placed somewhere in the wellbore as a secondary pressure seal before this primary pressure control system (heavy mud) was evacuated from the wellbore. But at the very least the mud replacement operation should have been heavily scrutinized. Clearly it was not.
6) Evidence provided at the hearing, including the pressure data transmitted from the rig for the last two hours before the explosion, is diagnostic. At 8:20 p.m. on the day of the explosion the pressure data suggest there was a constant flow of sea water being pumped into the drill pipe that was displacing the heavier mud system which was the primary pressure control for the well. The rate going in was 900 gallons per minute, but the flow data of mud coming out was steadily increasing from 900 gallons a minute at 8:20 p.m. to a rate of 1,200 gallons per minute at 8:34 p.m. During this 14-minute period one can conclude that hydrocarbons were flowing and pushing more fluid from the wellbore than was being pumped in.
This is what this data is supposed to monitor, but the well flow evidence would appear to have been ignored, because at this point the BP rig supervisors should have gone to a well kill operation and started to pump heavy mud back into the well bore to restore the primary control mechanism. Instead the mud continued to be evacuated.
7) At 9:08 there was another piece of evidence that is very clear cut. The sea water pump was shut down presumably to check the well stability. However, with the pump shut down a pressure increase was seen in the standpipe (SPP). This pressure response has to be associated with the reservoir flowing hydrocarbons and again at this point kill operations should have been initiated by the BP engineers.
From 9:08 p.m. to around 9:30, despite the sea-water pump either running at a constant volume or shut-in, the SPP continued to increase; again this is evidence that the well is producing hydrocarbons and should have caused a kill operation to be initiated.
9) At 9:30 p.m. the seawater pump was again shut-in to presumably observe what the well was doing, and again there is a notable increase in the standpipe pressure.
10) At 9:49 the SPP showed a very large increase and the explosion followed—this is obviously the point at which the gas and oil reached the drill floor and found an ignition source.
Mr. Hayward and BP have taken the position that this tragedy is all about a fail-safe blow-out preventer (BOP) failing, but in reality the BOP is really the backup system, and yes we expect that it will work. However, all of the industry practice and construction systems are aimed at ensuring that one never has to use that device. Thus the industry has for decades relied on a dense mud system to keep the hydrocarbons in the reservoir and everything that is done to maintain wellbore integrity is tested, and where a wellbore integrity test fails, remedial action is taken.
This well failed its casing integrity test and nothing was done. The data collected during a critical operation to monitor hydrocarbon inflow was ignored and nothing was done. This spill is about human failure and it is time BP put its hand up and admitted that.
Terry Barr
President
Samson Oil and Gas
Lakewood, Colo.
EXHIBIT C: Energy Information Administration
The United States imports approximately 62 percent of its oil. Canada supplies approximately 20 percent of these imports, and Mexico contributes 10 percent. But over 30 percent come from regimes that are less friendly or stable, including Saudi Arabia, Venezuela, Nigeria, Angola, Iraq, and Algeria (respectively the 2nd, 4th, 5th, 6th, 7th, and 8th largest oil importers to the United States).
EXHIBIT D: Energy Information Administration
Supply Related
U.S. Crude Oil Production
4,950 ,000 barrels/day
U.S. Crude Oil Imports
9,783 ,000 barrels/day
U.S. Petroleum Product Imports
3,132,000 barrels/day
U.S. Net Petroleum Imports
11,114,000 barrels/day
Dependence on Net Petroleum Imports
57.0%
Top U.S. Crude Oil Supplier
Canada - 1,956,000 barrels/day
Top U.S. Total Petroleum Supplier
Canada - 2,493,000 barrels/day
U.S. Crude Oil Imports from OPEC
5,954,000 barrels/day
U.S. Petroleum Product Imports from OPEC
540,000 barrels/day
State Ranking of Crude Oil Production
Texas - 1,087,000 barrels/day
Top U.S. Producing Companies (2007)
BP - 654,000 barrels/day
Top U.S. Oil Fields by Production (2007)
Prudhoe Bay, AK
Top Oil Producing Countries & Exporters
#1 - Saudi Arabia (10,782 Thousand bbls/day)
Top Oil Consuming Countries & Importers
#1 - United States (19,498 Thousand bbls/day)
EXHIBIT E: Crude Oil Bulletin
Although the USA GoM is only producing about 1.3 mbd, it remains the region of the biggest future capacity additions for the entire USA. The 250 kbd capacity Thunder Horse project started oil production in mid 2008 and BP claims that it is producing 200 kbd now, but it has not stopped the overall declining trend in GoM production. Blind Faith and Neptune also started in 2008, adding almost 100 kbd capacity, but they have not helped to reverse the declining GoM production trend.
2009 GoM projects include Shenzi, 85 kbd; Tahiti, 125 kbd; and Thunder Hawk, 60 kbd. Will these projects combined with the 2008 projects reverse the declining GoM production trend?
Deepwater GoM projects face numerous production constraints. These include hurricanes, planned and unplanned maintenance, and production ramp up delays due to engineering challenges. In addition, current low oil prices and credit constraints may delay some projects. Production decline rates for mature GoM fields are about 20% per year according to the IEA.
If it's assumed that a 20% decline rate is applied to 1 mbd of GoM production, then additional production additions of 200 kbd are required every year just to keep GoM production constant. 2008 total GoM capacity additions might be as high as 360 kbd. However, 2008 production additions are probably closer to 250 kbd, on an annual basis. Similarly, 2009 GoM capacity additions might be 270 kbd of which about 200 kbd will probably be production additions for 2009.
There is some hope that recent GoM discoveries could increase GoM production. In 2006, Chevron made a large oil discovery at the Jack well in the lower tertiary trend thought to hold as much as 15 billion barrels. This month, Chevron announced another oil discovery also in the lower tertiary trend, called Buckskin. Anadarko announced two GoM discoveries this month, Shenandoah and Heidelberg. Unfortunately, it appears unlikely that these discoveries will reverse the declining production trend as it could be at least five years until first oil is produced from these discoveries. For example, Chevron's CEO Dave O'Reilly recently stated that he hoped production from Jack would start before 2015.
Since 2003, oil discoveries have not been sufficient to replace reserves lost to production. About 95% of GoM crude oil proved reserves are located in Federal Offshore Louisiana and Alabama. These reserves have been in a declining trend from the peak of 4.25 Gb in 2003 down to 3.32 Gb in 2007 shown below in the chart from the EIA.
It is possible that GoM production will stay constant over the short term from 2008 to 2010. However, long term GoM production will probably continue its decline from the 2002 peak because sanctioned capacity additions beyond 2010 are less than 100 kbd per year which are not enough to offset production declines from existing fields. This indicates that USA crude and condensate (C&C) production will also continue its long term decline from its peak in 1970. According to the EIA, USA C&C production in 2004 was 5.42 mbd; 2005, 5.18 mbd; 2006, 5.10 mbd; 2007, 5.06 mbd; and 2008 YTD November, 4.94 mbd
EXHIBIT F: 2007 WORLD OIL PRODUCTION (Source: CIA World Fact Book)
1 World
83,000,000
2 Saudi Arabia
9,475,000
3 Russia
9,400,000
4 United States
7,610,000
5 Iran
3,979,000
6 China
3,631,000
7 Mexico
3,420,000
8 Norway
3,220,000
9 Canada
3,135,000
10 European Union
3,115,000
11 Venezuela
3,081,000
12 United Arab Emirates
2,540,000
13 Nigeria
2,451,000
14 Kuwait
2,418,000
15 Iraq
2,130,000
16 United Kingdom
2,075,000
17 Libya
1,720,000
18 Angola
1,600,000
19 Brazil
1,590,000
20 Algeria
1,373,000
EXHIBIT G: OIL PRODUCTION BY STATE
Home > Energy Information Sheets Index > Crude Oil Production
Crude Oil Production
Last Updated: March 2009
Next Update: February 2010
How Is Crude Oil Formed?
It is generally believed that crude oil was formed from the remains of animals and plants (called biomass) that lived millions of years ago. Over eons the biomass was covered by layers of mud, silt, and sand that formed into sedimentary rock. Geologic heat and the pressure of the overlying rock turned the biomass into a hydrocarbon-rich liquid that we call crude oil, and eventually forced it into porous rock strata called reservoirs. There are also formations or deposits of hydrocarbon-saturated sands and shale where geologic conditions have not been sufficient to turn the hydrocarbons into liquid.
How Is Crude Oil Produced?
Wells are drilled into oil reservoirs to extract the crude oil. "Natural lift" production methods that rely on the natural reservoir pressure to force the oil to the surface are usually sufficient for a while after reservoirs are first tapped. In some reservoirs, such as in the Middle East , the natural pressure is sufficient over a long time. The natural pressure in many reservoirs, however, eventually dissipates. Then the oil must be pumped out using “artificial lift” created by mechanical pumps powered by gas or electricity. Over time, these "primary" methods become less effective and "secondary" production methods may be used. A common secondary method is “waterflood” or injection of water into the reservoir to increase pressure and force the oil to the drilled shaft or "wellbore." Eventually "tertiary" or "enhanced" oil recovery methods may be used to increase the oil's flow characteristics by injecting steam, carbon dioxide and other gases or chemicals into the reservoir. In the United States, primary production methods account for less than 40% of the oil produced on a daily basis, secondary methods account for about half, and tertiary recovery the remaining 10%. Extracting oil (or “bitumen”) from oil/tar sand and oil shale deposits requires mining the sand or shale and heating it in a vessel or retort, or using “in-situ” methods of injecting heated liquids into the deposit and then pumping out the oil-saturated liquid.
What Affects Production Costs?
Reservoir characteristics (such as pressure) and physical characteristics of the crude oil are important factors that affect the cost of producing oil. Because these characteristics vary substantially among different geographic locations, the cost of producing oil also varies substantially. In 2007, average “lifting” costs (all the costs associated with bringing a barrel of oil to the surface) reported to EIA by the major private oil companies participating in the Financial Reporting System (FRS)1 ranged from about $3.87 per barrel (excluding taxes) in Central and South America to about $10.00 per barrel in Canada. The average for the U.S. was $8.35 per barrel (an increase of 18.5 percent over the $7.05 per barrel cost in 2006).
Besides the direct costs associated with removing the oil from the ground, substantial costs are incurred to explore for and develop oil fields (called “finding” costs), and these also vary substantially by region. Finding costs averaged over 2005, 2006, and 2007, ranged from about $4.77 per barrel in the Middle East to $49.54 per barrel for the U.S. offshore. While technological advances in finding and producing oil have made it possible to bring oil to the surface from more remote reservoirs at ever increasing depths, such as in the deepwater Gulf of Mexico, the total finding and lifting costs have increased sharply in recent years. Much of this recent increase is attributable to the rapid expansion of the world economy and is likely to reverse direction as the economic growth has slowed or delined in 2008/2009.
Source: Energy Information Adminstration, Performance Profiles of Major Energy Producers 2007
figure data
U.S. Crude Oil Production
The first commercial oil well in the U.S. was drilled in Titusville, Pennsylvania in 1859. Drilling activity and crude oil production expanded slowly to supply mostly lubricants and kerosene for use in lamps to replace whale oil. Production began to accelerate in the late 1800’s as crude oil refineries produced new petroleum products to meet demand for fuels and products by a rapidly industrializing country and the growing number of internal combustion engines. In 1859, U.S. production was about 2,000 barrels; in 1879 it was about 19 million barrels; and in 1899 it was about 57 million barrels. (A barrel contains 42 U.S. gallons.)
U.S. crude oil production peaked in 1970 and has declined gradually since then. In 1970, domestic production of crude oil (including lease condensate2) averaged 9.64 million barrels per day (MMbbl/d). In 2007, total U.S. domestic crude oil production, including Federal offshore, averaged 5.06 MMbbl/d, a decrease of about 47% from 1970.
Source: Energy Information Administration, Petroleum Navigator
figure data
Four States (Texas, Alaska, California, and Louisiana) produced 52% of total U.S. crude oil production in 2007. About 25 percent was produced on Federal Offshore-leases in the Gulf of Mexico (GOM), and the remaining 23 percent was produced in 24 other States and on Federal leases off the Pacific Coast (mainly California).
U.S. Crude Oil Production 2007 by Major Producing States and Federal Gulf of Mexico
(Million Barrels per Day)
