Sunday, August 1, 2010
Friday, July 30, 2010
BP's Deepwater Horizon - Static Top Kill vs. Bottom Kill: Weighing the Risks
A permanent solution to the BP Macondo blowout in the Gulf of Mexico may be achieved soon but there are risks. Admiral Thad Allen announced on Monday, July 26 that a static top kill would be attempted on August 2. The schedule may be accelerated to July 31 or August 1 according to an announcement today (July 29). The sealing cap has successfully stopped the flow of oil and gas from the well and the pressure continues to build slowly. Temperature at the wellhead has not increased, and seeps near the well are mostly nitrogen and biogenic methane unrelated to leakage. BP Senior Vice President Kent Wells’ technical update on July 21 explained these findings and showed how the well will be killed.
There are risks involved in both the top and bottom kill procedures. The purpose of this post is to describe those risks. There are two risks associated with the static top kill. First, it may not work at all and second, it may rupture the casing by pumping heavy mud under pressure (“bull heading”).
Kent Wells described the static top kill as a process of continuously pumping mud into the well until the oil is pushed into the reservoir. This is clearly erroneous and must be a simplification designed for the general public. What will more probably take place is a practice called “bleed and lubricate”. Heavy mud is pumped into the well through the choke and kill lines on the blowout preventer (BOP) and allowed to sink to the bottom of the well. Hopefully, the mud will retard the flow so that some of the pressure can be bled off by producing oil to the surface for a short period. Then, more heavy mud will be pumped into the well, and the process repeated as necessary until the well contains enough mud to kill the well.
The first problem with stopping the flow from the top is that it has to be an annular kill: the flow was coming up the annulus outside the production casing. This is a very narrow space so mud will have to pumped at high pressure to achieve entry. It will initially be working against a full column of gas and oil and the shut-in pressure at the well head. On the positive side, if produced sand has accumulated in the annulus, the operation may not have to contend with the full force of the reservoir pressure in addition to these obstacles. On the negative side, the well head seals might prevent or restrict downward flow, or the pumping pressure could rupture the 22-inch casing, or reach a pressure high enough to call off the operation.
Figure 1a (based on a government document) shows that the upper part of the well bore is protected by three strings of casing (36-, 28-, and 22-inch) and cement down to 7,937 feet (measured depth below sea level). A fourth string of 16-inch casing extends nearly from the well head to where it is cemented at 11,585 feet, but it is apparently hung inside the 22-inch casing at 5,227 feet, leaving a gap of 160 feet. The 16-inch pipe has a burst rating approximately equal to the current shut-in pressure of 6,900 psi (80% of rating), but the 22-inch pipe does not meet this standard.
BP has said that the relief well DD3 plan will continue regardless of the success of the top kill operation. The main risk with a bottom kill is that it may take considerable time to accomplish. Because of the recent tropical storm, crews are just removing the storm packer today, and it will take time to re-enter and condition the hole before drilling resumes. BP estimates that the DD3 will intersect the Macondo well around August 10. Most efforts to intersect a blown-out wells require several attempts. The recent 2009 Montara blowout in the Timor Sea required four attempts that took a month after the relief well was near the blow out and cased. The bottom of the first Macondo relief well is currently located a few feet from the target at approximately 17,220 feet measured depth (based on Wells’ update and shown in Figure 1b).
The good news is that, in this case, the relief well does not, apparently, need to intersect the well exactly--it just needs to be close. Once the relief well penetrates the reservoir, enough mud can be pumped to hopefully overcome flowing pressure and kill the well. The bottom-kill option has the same annular flow path liabilities as the top kill, but it has the capacity to deliver higher flow rates directly to the reservoir. This approach will not cause significant pressuring near the well head and should not, therefore, pose a risk of rupturing the 22-inch casing.
The bottom kill option involves considerably less mechanical risk than the top kill, but time is the enemy, so the top kill makes sense. Maintaining the objectivity to abandon the operation rather than risk casing rupture will be critical.
Wednesday, July 28, 2010
Arthur Berman talks about Shale Gas: An interview in ASPO-USA's Newsletter
Posted by Gail The Actuary on July 28, 2010 - 10:40am Topic: Supply/Production
Tags: Shale Gas
Recently, ASPO-USA's newsletter printed an interview (Part 1 and Part 2) with Oil Drum staff member Art Berman (aeberman). Art is a geological consultant whose specialties are subsurface petroleum geology, seismic interpretation, and database design and management. The people doing the interview are members of the "Peak Oil Review Team," abbreviated POR in the text below. This is the shale gas portion of the interview.
POR: Can you give us your latest updated perspective on the shale gas story?
Art Berman: You have to acknowledge that shale gas is a relatively new and significant contribution to North American supply. But I don’t believe it’s anywhere near the magnitude that is commonly discussed and cited in the press. There are a couple of key points here. First the reserves have been substantially overstated. In fact I think the resource number has been overstated.
Read the rest of the interview on The Oil Drum...
Monday, July 26, 2010
My interview on CNN American Morning
Sunday, June 27, 2010
Estimated Oil Flow Rates From the BP Mississippi Canyon Block 252 “Macondo” Well
Estimates of flow rates for the BP Deepwater Horizon “Macondo” well now range from 1,000-100,000 barrels of oil per day (bopd). Initial estimates were 1,000 bopd. These increased to 3,000 bopd and then to 5,000 bopd. Now the U.S. Geological Survey believes the well is flowing 20,000-40,000 bopd but other experts believe that flow rates may be as high as 60,000 bopd. Some have even suggested rates as high as 100,000 bopd, and others as high as 250,000 bopd. The purpose of this post is to provide a calibration framework for probable flow rates.
More than 8,700 wells drilled in the Gulf of Mexico since 1996 were evaluated using publicly-available production data from the Minerals Management Service (MMS). Wells in the deepwater Gulf of Mexico dominate the highest flow rates in this data set. Approximately 4,000 wells have been drilled in water depths more than 1000 ft, and more than 700 in more than 5,000 ft of water during the past 20 years. The Macondo well was drilled in 5,067 ft of water to a total depth of 18,360 ft below sea level.
Historical Context for High Flow Rates in the Gulf of Mexico
The highest flow rate for a single well in the Gulf of Mexico is 46,467 bopd (Figure 1) based on the daily average of the peak month of production. The mean of the 50 wells with the highest oil flow rates is 27,753 bopd. A probability plot (Figure 2) of these wells indicates that the most likely case is about 27,000 bopd (P50). There is a 10% probability (P10) that a well will produce 37,000 bopd, and a 90% probability (P90) that it will produce 20,000 bopd.
There is no historical precedent for a single well producing more than 100,000 bopd. Among historical blowouts, the highest flow rates known are approximately 100,000 bopd at the Spindletop Field in Texas in 1901, the Midway-Sunset Field in California in 1910, the Long Beach Field in California in 1910, and the Lake Maracaibo Field in 1922 (http://en.wikipedia.org/wiki/Blowout_%28well_drilling%29). These were all open-hole completions drilled without casing or drilling fluid so they represent maximum unconstrained flow rates.
The BP “Worst Case Scenario” Document
An internal BP “worst-case scenario” document released June 20 has been mis-interpreted by some to indicate that the company believes that flow rates as high as 100,000 bopd are possible (http://globalwarming.house.gov/mediacenter/pressreleases_2008?id=0272#main_content). The document states that the probable range is 5,000-40,000 bopd (http://globalwarming.house.gov/files/WEB/flowrateBP.pdf). It further states that the maximum theoretical rate is 60,000 bopd. It is important to note that these values represent unconstrained, open-flow rates that might be expected after removing the BOP from the well, and are estimated to be at least 10,000 bopd more than present flow. The 100,000 bopd rate assumes that flow is occurring within the production and casing and around the annulus. It again is an unconstrained rate.
The Most Likely Case
We know that the well is producing at least 25,000 bopd because that much has been collected in a single day. It is impossible to know the flow rate until the well is brought under control and rates and pressures can be measured. It is possible that the welll is flowing at a rate 25% higher rate than any well drilled to date (60,000 bopd) in the Gulf of Mexico, but it is not likely. It is less likely that it is flowing at 110% of the rate of the highest rate well so far (100,000 bopd). It is reasonable that it may be among the highest rate wells, and was initially flowing at 40,000-50,000 bopd.
Saturday, June 12, 2010
Impacts of President Obama’s Order Halting Work on 33 Exploratory Wells in the Deepwater Gulf of Mexico
Roughly 33% of nation’s domestically produced oil comes from the Gulf of Mexico, and 10% of the nation’s natural gas.
80% of the Gulf’s oil, and 45% of its natural gas comes from operations in more than 1000 feet of water – the deepwater (2009 data).
Suspension of operations means roughly 33 floating drilling rigs – typically leased for hundreds of thousands of dollars per day – will be idled for six months or longer.
$250,000 to $500,000 per day, per rig – results in roughly $8,250,000 to $16,500,000 per day in costs for idle rigs;
Secondary impacts include:
• Supply boats – 2 boats per rig with day rates of $15,000/day per boat - $30,000/day for 33 rigs – nearly $1 million/day
• Impacts to other supplies and related support services (i.e., welders, divers, caterers, transportation, etc.)
Jobs –
Each drilling platform averages 90 to 140 employees at any one time (2 shifts per day), and 180 to 280 for 2 2-week shifts
Each E&P job supports 4 other positions
Therefore, 800 to 1400 jobs per idle rig platform are at risk
Wages for those jobs average $1,804/weekly; potential for lost wages is huge, over $5 to $10 million for 1 month – per platform.
Wages lost could be over $165 to $330 million/month for all 33 platforms
Secondary impacts: Many offshore workers live in Louisiana. The state is going to see a decrease in income taxes and sales taxes that would normally be paid by those employees. (The state does not collect a sales tax on oilfield supplies and equipment used offshore.)
Companies Impacted:
Oil Companies Impacted
Shell has seven (7) exploratory wells that will be impacted
Others include:
Chevron (4)
Anadarko (3)
Marathon (2)
Noble Energy (2)
Eni US Operating Co. (2)
ATP Oil & Gas (2)
Statoil (2)
ExxonMobil (1)
Petrobras America (1)
BHP (1)
BP (1)
Kerr McGee (1)
Murphy (1)
LLOG (1)
Newfield (1)
Hess (1)
The 33 gulf wells where operations are suspended were the ones inspected immediately after the Deepwater Horizon blowout (per Interior Secretary Ken Salazar); in those inspections, “only minor problems were found on a couple of rigs”. Salazar believes “additional safety measures can be taken including dealing with cementing and casing of wells and significant enhancements and redundancies of blowout prevention mechanisms. Although these rigs passed the inspections, we will look at standards that are in place.”
Longer term impacts include
Idle drilling rigs in the Gulf could mean that they will be contracted overseas for work in other locations, and if/when the halt is lifted, rigs will not be available for completing the work in the Gulf.
Loss of tolls on LA Highway 1 resulting from loss of traffic related to deepwater operations; tolls go directly to retiring the bond debt for construction of LA Highway 1 improvements, and if those tolls are lost, the state of Louisiana – as the other responsible party on the bonds - will have to pay to retire that debt, meaning loss of funding for some other programs in the state’s budget.
A 6-month halt in new drilling would defer 80,000 barrels/day, or 4% of 2011 deepwater Gulf of Mexico production. (Wood MacKenzie)
Higher drilling costs might jeopardize exploration in frontier areas. More immediately, estimates are that seven current discoveries could be rendered sub-economic, putting U.S. $7.6 billion in future government revenues at risk. Proposals to increase the cap on oil companies’ liability for oil spill damages to U.S. $10 billion could exclude U.S. independents from offshore Gulf of Mexico activities. (Wood MacKenzie)
Since these wells are not yet producing, there is no decrease in the available oil supply. However, it could lead to a decrease in the availability of domestic oil, and it is hard to tell how commodity speculators are going to respond over the next six months; there is the possibility for driving oil prices to levels well over $100 per barrel.
Prepared May 28, 2010, based on most recent data available; will be updated as needed.
Saturday, May 22, 2010
What caused the Deepwater Horizon disaster?
The blowout and oil spill on the Deepwater Horizon in the Gulf of Mexico was caused by a flawed well plan that did not include enough cement between the 7-inch production casing and the 9 7/8-inch protection casing. The presumed blowout preventer (BOP) failure is an important but secondary issue. Although the resulting oil spill has potentially grave environmental implications, recent efforts to limit the flow with an insertion tube have apparently been effective. Continuous efforts to slow or stop the flow include drilling two nearby relief wells that may intersect the MC 252 wellbore within 60-90 days.
