Here is the link to Kudlow's Money Politics 27 June 2011
http://www.msnbc.msn.com/id/21134540/vp/43556438#43556438
Thursday, June 30, 2011
Wednesday, June 29, 2011
Why I Support Hydraulic Fracturing
Some of you have asked if I am for or against hydraulic fracturing (fracking). I support it
The oil and gas industry has been using this stimulation technique commercially since 1949. Among the tens of thousands of wells that have been hydraulically fractured, there are few documented cases in which contamination of shallow aquifers has occurred. In those rare instances, the cause has been overwhelmingly because of improper pumping procedures or pipe specifications that have allowed parting of the conductor casing and cement that protects the aquifer. In other cases, contamination of aquifers occurred because natural gas liberated by the fracturing process found its way into improperly plugged vertical wells nearby. These unfortunate situations are preventable.
The Environmental Protection Agency (EPA) published a report in 2004 which concluded that hydraulic fracturing of coal-bed methane wells had minimal effect on groundwater quality. Since coal-bed methane wells are generally very shallow, they have higher likelihood of affecting aquifers than oil and gas wells drilled thousands of feet deeper. EPA is currently studying the impact of hydraulic fracturing on shale gas wells. The conclusion of research is expected by the end of 2012 and the study should be published in 2014.
I respect the concerns of people living in the vicinity of oil and gas wells that have been or will be hydraulically fractured. At the same time, it is difficult for me to imagine that fluids injected thousands of feet underground can migrate through multiple sealing rock formations into aquifers a few tens or hundreds of feet below the surface. The pressure requirements to do this are far beyond any pumping technology.
Hydraulic fracturing is critical to unlock the oil and natural gas found in low permeability reservoirs. There are risks associated with this stimulation technology. Those who fear the potential negative effects of fracturing must balance their concerns with their need for a continual supply of electricity generated by burning natural gas. They should also weigh the more negative impact of burning coal, the only viable alternative at least for the short term.
The oil and gas industry has been using this stimulation technique commercially since 1949. Among the tens of thousands of wells that have been hydraulically fractured, there are few documented cases in which contamination of shallow aquifers has occurred. In those rare instances, the cause has been overwhelmingly because of improper pumping procedures or pipe specifications that have allowed parting of the conductor casing and cement that protects the aquifer. In other cases, contamination of aquifers occurred because natural gas liberated by the fracturing process found its way into improperly plugged vertical wells nearby. These unfortunate situations are preventable.
The Environmental Protection Agency (EPA) published a report in 2004 which concluded that hydraulic fracturing of coal-bed methane wells had minimal effect on groundwater quality. Since coal-bed methane wells are generally very shallow, they have higher likelihood of affecting aquifers than oil and gas wells drilled thousands of feet deeper. EPA is currently studying the impact of hydraulic fracturing on shale gas wells. The conclusion of research is expected by the end of 2012 and the study should be published in 2014.
I respect the concerns of people living in the vicinity of oil and gas wells that have been or will be hydraulically fractured. At the same time, it is difficult for me to imagine that fluids injected thousands of feet underground can migrate through multiple sealing rock formations into aquifers a few tens or hundreds of feet below the surface. The pressure requirements to do this are far beyond any pumping technology.
Hydraulic fracturing is critical to unlock the oil and natural gas found in low permeability reservoirs. There are risks associated with this stimulation technology. Those who fear the potential negative effects of fracturing must balance their concerns with their need for a continual supply of electricity generated by burning natural gas. They should also weigh the more negative impact of burning coal, the only viable alternative at least for the short term.
On the other side, the oil and gas industry should be more sensitive to the public's fears, and should be more forthcoming with information about the chemicals pumped into oil and gas reservoirs. We should also willingly undertake stricter self-regulation anticipating the less desirable but inevitable government intervention if we do nothing.
Saturday, January 1, 2011
EIA Annual Energy Outlook 2011: Don’t Worry, Be Happy.
See my post on The Oil Drum: http://www.theoildrum.com/node/7285
We no longer have to worry about energy supply or prices. That is the message from the U.S. Energy Information Administration’s (EIA) Annual Energy Outlook (AEO) 2011. Cheap energy will characterize the world for most of the next decade, according to the report. Oil will not reach $100 per barrel until 2017 and natural gas will remain below $5 per thousand cubic feet (mcf) until 2022 (Figure 1).
Despite four decades of oil shocks and natural gas price spikes, the future looks stable with supply and demand comfortably balanced (Figure 2). Wasn’t it just two-and-a-half years ago that $147 per barrel oil helped push the world into the current global recession? The EIA forecast is as troubling for the smooth and gradual progression of oil and gas prices as it is for the improbably low values of those prices. The history of oil and gas price, supply and demand is characterized above all by volatility but the EIA projection does not reflect this characteristic. Don’t worry, be happy.
Natural Gas
The headline of the AEO 2011 Early Release Overview (http://www.eia.gov/forecasts/aeo/) published December 16, 2010 is that shale gas resources in the U.S. have more than doubled since last year’s report. The current estimate is 827 trillion cubic feet (tcf) of gas, up 474 tcf from last year’s assessment of 353 tcf. The new figure is 25% higher than the Potential Gas Committee’s (PGC) 661 tcf from shale in its June 2009 report (http://www.mines.edu/Potential-Gas-Committee-reports-unprecedented-incre...). Notably, the PGC also presented a “probable” case of total gas resources of 441 tcf. Shale gas represents approximately one third of this estimate and is 17% of the EIA estimate (147 tcf). We hope to get more detail on how the EIA determined total and shale gas resources, along with other aspects of the EIA Outlook when the full AEO 2011 is released in March.
Technically recoverable resources should never be confused with reserves because resources do not take commercial considerations into account. These may be in accumulations so small or so deep that the gas may never be drilled or produced at any price, or may be in areas that are off limits or impractical to drill. It includes plays and basins that are, as yet, untested.
A resource assessment begins by estimating a total resource in place based on assumptions about gas richness, shale thickness, thermal maturity and areal distribution. A technically recoverable resource is a sub-set of the total resource that is determined by eliminating areas where one or more of these factors are marginal. There is great uncertainty involved in both of these estimated volumes. The expectation of future production based on as yet uncertain current production decline models is a key factor. For North America, The Baker Institute estimates 583 tcf of technically recoverable shale gas resources. Other estimates include Navigant Consulting (900 tcf), the Potential Gas Committee (661 tcf), and ARI (1000 tcf).
Given the variations in these recent evaluations (2008-2010) by credible organizations, resource estimates should not have much bearing on future production volume or price forecasts. The EIA, however, takes a different view. Slide 27 in Richard Newell’s December 26 unveiling of the AEO 2011 states, “Natural gas price projections are significantly lower than past years due to an expanded shale gas resource base” (Figure 3).
The only volume that really matters is proved developed reserves. While the EIA’s estimate of resources has doubled since last year, proved reserves only increased 2.5% in 2010 (EIA AEO 2011). Much of this increase will likely be proved undeveloped reserves (PUD) thanks to revisions in Securities and Exchange Commission definitions for 2009. Clearly, the commerciality of undeveloped reserves is more questionable than proved developed reserves.
The EIA fails to grasp that the exploration and production business succeeds or fails based on earnings and profit, and not on production growth, resource or even reserve additions. Natural gas operators require at least $7.00 per mcf on average to break even in the shale plays (Figure 5).
It further implies that unprecedented increases in nuclear, hydroelectric, biofuels and renewable energy sources will magically materialize to meet growing U.S. energy demand. EIA forecasts also imply that global liquids production will reach 115 mmbopd before 2035 while other estimates, including those by the IEA (International Energy Agency), do not anticipate that production can exceed 100 mmbopd (Figure 10), and many doubt that it can even reach that level. In any case, the price of oil would have to be substantially higher than EIA estimates to reach the production levels that it predicts.
Conclusions
It is understandable that the EIA, as a branch of government, must produce an annual report that is politically expedient and that supports a view that meets public policy expectations. The EIA approach takes a long-term economic view and is, therefore, not concerned with the fluctuations that characterize the real world of petroleum supply, demand and price. At the same time, it is not useful that this report is in conflict with industry best practices and opinion as well as trend data available to the public.
The EIA’s resource estimate of technically recoverable gas from shale is interesting but not relevant to future price or production volume forecasts. The Potential Gas Committee’s 2009 report is the benchmark of credibility, and we hope that the full EIA report in March will explain why we should accept unwarranted and insupportable upward revisions to PGC resource estimates and how these might translate to energy reserves and price. The EIA treats shale gas just like conventional gas in its forecasting and does not acknowledge the much higher decline rates and, therefore, great number of wells required to maintain supply.
Exploration and production companies involved in shale gas production have presented a position that emphasizes production and reserve growth over earnings or profit. It is confusing that the EIA has assumed that market forces and improving efficiencies will save the day for oil and gas prices. It would be more appropriate to frame the problem in the context of reasonable expectations that would be useful to public understanding of the shale gas phenomenon and its potential contribution to natural gas volumes and price. It is unsettling that the EIA has not acknowledged the belief by the U.S. military and other credible sources of an impending liquid fuel shortage that confronts the United States and the world (e.g. Hirsch, Benzdek and Wendling, 2010; JOE Report) . Instead, the EIA has provided an unrealistic view of future oil and gas supply and price that will inevitably not serve public understanding or promote reasonable planning for resource availability or price.
We no longer have to worry about energy supply or prices. That is the message from the U.S. Energy Information Administration’s (EIA) Annual Energy Outlook (AEO) 2011. Cheap energy will characterize the world for most of the next decade, according to the report. Oil will not reach $100 per barrel until 2017 and natural gas will remain below $5 per thousand cubic feet (mcf) until 2022 (Figure 1).
Despite four decades of oil shocks and natural gas price spikes, the future looks stable with supply and demand comfortably balanced (Figure 2). Wasn’t it just two-and-a-half years ago that $147 per barrel oil helped push the world into the current global recession? The EIA forecast is as troubling for the smooth and gradual progression of oil and gas prices as it is for the improbably low values of those prices. The history of oil and gas price, supply and demand is characterized above all by volatility but the EIA projection does not reflect this characteristic. Don’t worry, be happy.
Natural Gas
The headline of the AEO 2011 Early Release Overview (http://www.eia.gov/forecasts/aeo/) published December 16, 2010 is that shale gas resources in the U.S. have more than doubled since last year’s report. The current estimate is 827 trillion cubic feet (tcf) of gas, up 474 tcf from last year’s assessment of 353 tcf. The new figure is 25% higher than the Potential Gas Committee’s (PGC) 661 tcf from shale in its June 2009 report (http://www.mines.edu/Potential-Gas-Committee-reports-unprecedented-incre...). Notably, the PGC also presented a “probable” case of total gas resources of 441 tcf. Shale gas represents approximately one third of this estimate and is 17% of the EIA estimate (147 tcf). We hope to get more detail on how the EIA determined total and shale gas resources, along with other aspects of the EIA Outlook when the full AEO 2011 is released in March.
Technically recoverable resources should never be confused with reserves because resources do not take commercial considerations into account. These may be in accumulations so small or so deep that the gas may never be drilled or produced at any price, or may be in areas that are off limits or impractical to drill. It includes plays and basins that are, as yet, untested.
A resource assessment begins by estimating a total resource in place based on assumptions about gas richness, shale thickness, thermal maturity and areal distribution. A technically recoverable resource is a sub-set of the total resource that is determined by eliminating areas where one or more of these factors are marginal. There is great uncertainty involved in both of these estimated volumes. The expectation of future production based on as yet uncertain current production decline models is a key factor. For North America, The Baker Institute estimates 583 tcf of technically recoverable shale gas resources. Other estimates include Navigant Consulting (900 tcf), the Potential Gas Committee (661 tcf), and ARI (1000 tcf).
Given the variations in these recent evaluations (2008-2010) by credible organizations, resource estimates should not have much bearing on future production volume or price forecasts. The EIA, however, takes a different view. Slide 27 in Richard Newell’s December 26 unveiling of the AEO 2011 states, “Natural gas price projections are significantly lower than past years due to an expanded shale gas resource base” (Figure 3).
For the EIA, increased estimates for U.S. shale gas resources equate to higher production volumes, lower prices, and decreased imports of natural gas with shale gas accounting for 45% of total supply by 2035 (Figure 4). Average annual gas prices are 20-25% lower than predictions made a year ago in AEO 2010.
The only volume that really matters is proved developed reserves. While the EIA’s estimate of resources has doubled since last year, proved reserves only increased 2.5% in 2010 (EIA AEO 2011). Much of this increase will likely be proved undeveloped reserves (PUD) thanks to revisions in Securities and Exchange Commission definitions for 2009. Clearly, the commerciality of undeveloped reserves is more questionable than proved developed reserves.
The EIA fails to grasp that the exploration and production business succeeds or fails based on earnings and profit, and not on production growth, resource or even reserve additions. Natural gas operators require at least $7.00 per mcf on average to break even in the shale plays (Figure 5).
Favorable hedge positions over the past five years have carried companies through fluctuating and, more recently, low product prices. With futures strips now below $5.00/mcf for the next twelve months, hedges fail to guarantee the marginal cost of production.
While shale play enthusiasts have claimed profitability at gas prices below $5/mcf in recent years, these half-cycle economics do not include significant “fixed” and “sunk” costs such as debt service and overhead. With the flight to liquids-rich plays in recent months, the truth about true cost is being revealed. Chesapeake Energy, the paragon of shale operators, states in their most recent investor presentation that they do not intend to drill anything other than obligation wells in gas plays “until natural gas prices rise above $6.00 per mcf” (Figure 6). This reveals their commercial threshold despite past claims of profit at lower gas prices.
The EIA gas price forecast, therefore, implies that operating companies will continue to drill and produce gas at a loss for the next decade. This cannot happen. Because of the high decline rates of shale gas wells, drilling must continue at current rates just to maintain production rates.
Because some large operators in the Barnett Shale stopped drilling new wells in 2010, we can determine true portfolio decline rates, and they are substantially greater than predicted hyperbolic decline models. Figure 7 shows that the portfolio production decline rate is more than 40% for Barnett Shale wells operated by Encana, ConocoPhillips, Range Resources and Williams.
For shale gas production to double and reach 45% of total U.S. supply as the EIA predicts by 2035 (Figure 4), rig counts will have to more than double. This cannot happen unless gas prices rise substantially beyond EIA predictions regardless of improvements in drilling efficiency and economies of scale.
The most likely average natural gas spot price for 2011 will be $4.10/mcf (J. M. Bodell, personal communication). Toward the end of the year, it is possible that gas prices will strengthen toward $5.00 as drilling to hold land by production decreases.
Crude Oil
The EIA’s assessment of crude oil supply, demand and price is similarly puzzling by its departure from current data and considerable informed opinion that oil price will rise in the near term. The projection that oil prices will remain below $100 per barrel until 2017 conflicts with every credible source on the topic. The U.S. military, the world's largest single consumer of oil, has publicly stated its belief that there may be a liquid fuel shortage by 2012 (Joint Operating Environment (JOE) Report, 2010:http://www.jfcom.mil/newslink/storyarchive/2010/JOE_2010_o.pdf).
Oil closed at $91.51 on Friday, December 24, 2010 and will probably end 2010 at an average price of about $79.50 per barrel, yet the EIA estimate for the year is $78.03. Many experts predict that oil prices will exceed $100 per barrel in 2010, but my sources indicate that West Texas Intermediate crude oil prices will average $88 per barrel (J. M. Bodell, personal communication) but will increase to $95 or $100 per barrel later in the year.
The main factor that will control crude oil prices in 2011 is demand from the developing economies of countries outside of the OECD (Organization for Economic Cooperation and Development). Demand is expected to increase 3.6% (IEA) among developing nations and this should challenge OPEC (Organization of the Petroleum Exporting Countries) spare capacity. Because of subsidized oil and motor fuel prices in all OPEC countries, crude oil demand is largely insensitive to price. In contrast, the IEA predicts that oil demand in OECD countries will decrease 0.5% in 2011.
The EIA AEO 2011 report features a 14% increase in U.S. crude oil and lease condensate production from 2011 to 2020 (Figure 8) despite an 8 percent decline in production over the past decade and a 44% decrease since the 1970 U.S. production peak (Figure 9).
It further implies that unprecedented increases in nuclear, hydroelectric, biofuels and renewable energy sources will magically materialize to meet growing U.S. energy demand. EIA forecasts also imply that global liquids production will reach 115 mmbopd before 2035 while other estimates, including those by the IEA (International Energy Agency), do not anticipate that production can exceed 100 mmbopd (Figure 10), and many doubt that it can even reach that level. In any case, the price of oil would have to be substantially higher than EIA estimates to reach the production levels that it predicts.
Conclusions
It is understandable that the EIA, as a branch of government, must produce an annual report that is politically expedient and that supports a view that meets public policy expectations. The EIA approach takes a long-term economic view and is, therefore, not concerned with the fluctuations that characterize the real world of petroleum supply, demand and price. At the same time, it is not useful that this report is in conflict with industry best practices and opinion as well as trend data available to the public.
The EIA’s resource estimate of technically recoverable gas from shale is interesting but not relevant to future price or production volume forecasts. The Potential Gas Committee’s 2009 report is the benchmark of credibility, and we hope that the full EIA report in March will explain why we should accept unwarranted and insupportable upward revisions to PGC resource estimates and how these might translate to energy reserves and price. The EIA treats shale gas just like conventional gas in its forecasting and does not acknowledge the much higher decline rates and, therefore, great number of wells required to maintain supply.
Exploration and production companies involved in shale gas production have presented a position that emphasizes production and reserve growth over earnings or profit. It is confusing that the EIA has assumed that market forces and improving efficiencies will save the day for oil and gas prices. It would be more appropriate to frame the problem in the context of reasonable expectations that would be useful to public understanding of the shale gas phenomenon and its potential contribution to natural gas volumes and price. It is unsettling that the EIA has not acknowledged the belief by the U.S. military and other credible sources of an impending liquid fuel shortage that confronts the United States and the world (e.g. Hirsch, Benzdek and Wendling, 2010; JOE Report) . Instead, the EIA has provided an unrealistic view of future oil and gas supply and price that will inevitably not serve public understanding or promote reasonable planning for resource availability or price.
Sunday, August 1, 2010
Friday, July 30, 2010
BP's Deepwater Horizon - Static Top Kill vs. Bottom Kill: Weighing the Risks
The original version of this post is on The Oil Drum
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.
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
Arthur Berman talks about Shale Gas
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...
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
View my interview about the BP Macondo well on CNN American Morning: http://www.youtube.com/watch?v=Zv2ONRlaLNc
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