Posts
Monday, September 6, 2010
Energy Issues in the Alaska Gubernatorial Race
Over the next several weeks I will add articles to this blog discussing the various oil and gas and gas pipeline issues being proposed by the Alaska gubernatorial candidates. So far, topics included in those articles will be Owning a Piece of the Pipe, AGIA, and Changing the State’s Oil and Gas Royalty and Tax Structure. As the candidates publish additional positions on various issues I will try to include analysis of those positions in future articles.
Friday, July 30, 2010
Alaska Gasline Port Authority Proposal to Purchase Fairbanks Natural Gas LLC
The purchase of FNG by AGPA
The Fairbanks North Star Borough (FNSB) is currently considering authorizing the Alaska Gasline Port Authority (AGPA) to purchase Fairbanks Natural Gas LLC (FNG) as part of its proposal to truck natural gas from the Alaska North Slope to Fairbanks. In order to understand if that is a reasonable decision the FNSB needs to determine why AGPA is asking to purchase FNG. What is the goal they are trying to achieve, and what process should be followed to make that decision?
What is the goal the FNSB is trying to achieve or the value it is trying to protect?
The cost of energy has always been high in the Interior of Alaska. It is an important goal for the FNSB to ensure that future energy needs are met and that those needs are met in the most economic, cost-effective manner possible. The AGPA has proposed the purchase of Fairbanks Natural Gas LLC and the trucking of natural gas from the Alaska North Slope to Fairbanks as the method to achieve that goal. Before a decision on that issue can be made, several questions need to be answered in order to provide the context and justification for the decision, and a reasonable decision-making process needs to be followed to ensure a thorough analysis occurs. The decision should only be made to move forward with the purchase of FNG if the FNSB understands the economics and chance of success of the proposal and of the other alternatives available to the FNSB to meet its goal of long-term, low-cost energy.
What alternatives are available to meet future energy needs of the FNSB?
The AGPA has proposed the trucking of natural gas from the North Slope to Fairbanks as the most economic way to accomplish the goal of low-cost energy for the FNSB. Their proposal includes the purchase Fairbanks Natural Gas LLC (FNG) as a requirement to make that proposal a success. The assumption that trucking natural gas from the North Slope and the assumption that this necessarily means the purchase of FNG as a requirement to meet their goal must be tested against an analysis of the other viable alternatives available to meet the energy needs of the FNSB. This should be achieved through a reasonable agreed upon decision-making process. The following is a proposed process that could meet the need for a thorough analysis prior to making a decision of such magnitude.
What process should be followed before proceeding ahead with the FNG purchase?
First, compare trucking North Slope gas to all the other viable alternatives. Understand the proposed decision in context. For example, the cost of this alternative is substantially greater and the benefit (reduced energy cost) is substantially less than the benefit to the FNSB if a large diameter gas line is built. If a large diameter gas pipeline is built, the cost of energy from that pipeline will be substantially less than trucking natural gas from the North Slope to Fairbanks. But from a control and chance of success standpoint, trucking gas from the North Slope has a much greater chance of success than depending on TransCanada and the North Slope producers to build a large diameter gas pipeline.
The FNSB must also understand that if the utilities sign long-term contracts with FNG, the utilities will not need gas from the large diameter gas pipeline nor will the FNSB be able to benefit from a reduced cost of energy standpoint from a large diameter gas pipeline if it is successful. That doesn’t mean that the FNSB won’t receive any benefit from a successful large diameter gas pipeline, just that the FNSB will not be able to benefit from the reduced cost of energy that a large diameter gas pipeline would bring; the FNSB and the entire state will definitely benefit from a large diameter gasline from a jobs and taxes standpoint.
The economics of importing gas into Cook Inlet and building a gas pipeline from Cook Inlet to Fairbanks or trucking gas from Cook Inlet to Fairbanks should also be understood in comparison to the alternative AGPA is proposing.
Some have proposed building a small diameter gas pipeline from the North Slope as their preferred option. Will that project deliver gas to Fairbanks cheaper than trucking gas from the North Slope? What are the chances of that project moving forward to successful completion?
Other viable energy alternative should also be considered. Basic economics and the chance of success of each option should be the basis for any decision to move forward with an alternative.
In addition, a cost-benefit analysis of the proposed trucking option should be conducted. Assuming what GVEA says about cost savings is true and that electric bills will be reduced by about 6 percent and that 1,100 natural gas customers would save an estimated 30 percent on their electric bills, how much will be saved by the residents of the FNSB. Compare what would be saved each year over the term of the contracts to the cost of participating in the project. If the cost of the project outweighs the benefits of the project, it shouldn’t move forward with FNSB support even if it is the most viable alternative among those considered. This would be the no action alternative because none of the alternatives considered are worth supporting.
If trucking gas from the North Slope is determined to be the most economic viable alternative, what next?
If trucking gas from the North Slope is determined to be the most economic viable alternative, then the FNSB’s next decision is to what extent should the FNSB participate in the project in order to assure the project’s success.
A sovereign’s responsibility, as it relates to economic development, is normally to create a commercial environment where business can excel and grow while protecting the interests of the people. Only when a project is deemed to be essential for the benefit of the people and the business community is not willing to move forward with a project should the sovereign venture into participation in the economic arena and then only to the extent necessary assure the success of the project.
Once it is determined that participation by the sovereign in a project is essential to move a project forward, the next determination to be made is to what extent should the sovereign participate in the project. The sovereign should only participate in a project to the level necessary to accomplish the goal of moving the project forward. That participation could exhibit itself in the form of financing or ownership of any part of the project required to make the project a success.
If commercial entities had determined that the project was economic, they would have pursued the project and the AGPA wouldn’t have been given the option to participate. The FNSB, through participation of the AGPA will be required to participate by financing or ownership of the riskiest portions of the project because no commercial entity can be found to risk their capital on those portions of the project. No commercial entity can be found to take the investment risk necessary to participate in those portions of the project.
It is possible that no commercial entity can be found to participate in any portion of the project or that only a fully integrated ownership of the project makes the project viable for participation by the FNSB through AGPA. In that case there is one remaining step in the process to complete.
Valuation and purchase of the FNG asset.
If it is determined that trucking natural gas from the North Slope provides Fairbanks with the most viable low-cost energy alternative, and that no commercial entity wishes to participate in any portion of the project, or that an integrated operation is required to make the project viable, then purchase of FNG becomes a critical element in moving the project forward.
The last step is to properly value the FNG assets before a purchase offer is made or a purchase price is agreed upon. Project value should not be based on the value it ultimately brings to the FNSB, i.e., the value of the benefit to the people of Fairbanks over time. That could be tens of millions of dollars. The value should be based on what a commercial entity would pay for FNG in an arm’s length economic transaction. Based on this type of analysis a reasonable purchase price for FNG can be negotiated.
Summary
First, any action the FNSB takes in support of any proposal to bring natural gas to Fairbanks should be made in the context of how it accomplishes the goal of providing long-term, low-cost energy to Interior Alaska. At every stage of the process, what is being proposed and evaluated should be evaluated in the context of how it increases the likelihood of accomplishing the goal of long-term low-cost energy for Fairbanks. Don’t lose sight of the goal.
Next, if the above analysis is followed, and after careful and thorough economic and public policy considerations, the trucking option is chosen as a viable option to pursue, and ownership of the entire integrated operation is required, and a reasonable economic/commercial price is negotiated, then it may be reasonable to proceed ahead with this venture. But, to move forward with a project without a thorough analysis through a well-defined process is shortsighted and could lead to poor decision-making and increased risk of failure of the project. The FNSB needs to complete a thorough review of the proposal through a well thought-out process before it gives the green light for AGPA to purchase FNG.
The Fairbanks North Star Borough (FNSB) is currently considering authorizing the Alaska Gasline Port Authority (AGPA) to purchase Fairbanks Natural Gas LLC (FNG) as part of its proposal to truck natural gas from the Alaska North Slope to Fairbanks. In order to understand if that is a reasonable decision the FNSB needs to determine why AGPA is asking to purchase FNG. What is the goal they are trying to achieve, and what process should be followed to make that decision?
What is the goal the FNSB is trying to achieve or the value it is trying to protect?
The cost of energy has always been high in the Interior of Alaska. It is an important goal for the FNSB to ensure that future energy needs are met and that those needs are met in the most economic, cost-effective manner possible. The AGPA has proposed the purchase of Fairbanks Natural Gas LLC and the trucking of natural gas from the Alaska North Slope to Fairbanks as the method to achieve that goal. Before a decision on that issue can be made, several questions need to be answered in order to provide the context and justification for the decision, and a reasonable decision-making process needs to be followed to ensure a thorough analysis occurs. The decision should only be made to move forward with the purchase of FNG if the FNSB understands the economics and chance of success of the proposal and of the other alternatives available to the FNSB to meet its goal of long-term, low-cost energy.
What alternatives are available to meet future energy needs of the FNSB?
The AGPA has proposed the trucking of natural gas from the North Slope to Fairbanks as the most economic way to accomplish the goal of low-cost energy for the FNSB. Their proposal includes the purchase Fairbanks Natural Gas LLC (FNG) as a requirement to make that proposal a success. The assumption that trucking natural gas from the North Slope and the assumption that this necessarily means the purchase of FNG as a requirement to meet their goal must be tested against an analysis of the other viable alternatives available to meet the energy needs of the FNSB. This should be achieved through a reasonable agreed upon decision-making process. The following is a proposed process that could meet the need for a thorough analysis prior to making a decision of such magnitude.
What process should be followed before proceeding ahead with the FNG purchase?
First, compare trucking North Slope gas to all the other viable alternatives. Understand the proposed decision in context. For example, the cost of this alternative is substantially greater and the benefit (reduced energy cost) is substantially less than the benefit to the FNSB if a large diameter gas line is built. If a large diameter gas pipeline is built, the cost of energy from that pipeline will be substantially less than trucking natural gas from the North Slope to Fairbanks. But from a control and chance of success standpoint, trucking gas from the North Slope has a much greater chance of success than depending on TransCanada and the North Slope producers to build a large diameter gas pipeline.
The FNSB must also understand that if the utilities sign long-term contracts with FNG, the utilities will not need gas from the large diameter gas pipeline nor will the FNSB be able to benefit from a reduced cost of energy standpoint from a large diameter gas pipeline if it is successful. That doesn’t mean that the FNSB won’t receive any benefit from a successful large diameter gas pipeline, just that the FNSB will not be able to benefit from the reduced cost of energy that a large diameter gas pipeline would bring; the FNSB and the entire state will definitely benefit from a large diameter gasline from a jobs and taxes standpoint.
The economics of importing gas into Cook Inlet and building a gas pipeline from Cook Inlet to Fairbanks or trucking gas from Cook Inlet to Fairbanks should also be understood in comparison to the alternative AGPA is proposing.
Some have proposed building a small diameter gas pipeline from the North Slope as their preferred option. Will that project deliver gas to Fairbanks cheaper than trucking gas from the North Slope? What are the chances of that project moving forward to successful completion?
Other viable energy alternative should also be considered. Basic economics and the chance of success of each option should be the basis for any decision to move forward with an alternative.
In addition, a cost-benefit analysis of the proposed trucking option should be conducted. Assuming what GVEA says about cost savings is true and that electric bills will be reduced by about 6 percent and that 1,100 natural gas customers would save an estimated 30 percent on their electric bills, how much will be saved by the residents of the FNSB. Compare what would be saved each year over the term of the contracts to the cost of participating in the project. If the cost of the project outweighs the benefits of the project, it shouldn’t move forward with FNSB support even if it is the most viable alternative among those considered. This would be the no action alternative because none of the alternatives considered are worth supporting.
If trucking gas from the North Slope is determined to be the most economic viable alternative, what next?
If trucking gas from the North Slope is determined to be the most economic viable alternative, then the FNSB’s next decision is to what extent should the FNSB participate in the project in order to assure the project’s success.
A sovereign’s responsibility, as it relates to economic development, is normally to create a commercial environment where business can excel and grow while protecting the interests of the people. Only when a project is deemed to be essential for the benefit of the people and the business community is not willing to move forward with a project should the sovereign venture into participation in the economic arena and then only to the extent necessary assure the success of the project.
Once it is determined that participation by the sovereign in a project is essential to move a project forward, the next determination to be made is to what extent should the sovereign participate in the project. The sovereign should only participate in a project to the level necessary to accomplish the goal of moving the project forward. That participation could exhibit itself in the form of financing or ownership of any part of the project required to make the project a success.
If commercial entities had determined that the project was economic, they would have pursued the project and the AGPA wouldn’t have been given the option to participate. The FNSB, through participation of the AGPA will be required to participate by financing or ownership of the riskiest portions of the project because no commercial entity can be found to risk their capital on those portions of the project. No commercial entity can be found to take the investment risk necessary to participate in those portions of the project.
It is possible that no commercial entity can be found to participate in any portion of the project or that only a fully integrated ownership of the project makes the project viable for participation by the FNSB through AGPA. In that case there is one remaining step in the process to complete.
Valuation and purchase of the FNG asset.
If it is determined that trucking natural gas from the North Slope provides Fairbanks with the most viable low-cost energy alternative, and that no commercial entity wishes to participate in any portion of the project, or that an integrated operation is required to make the project viable, then purchase of FNG becomes a critical element in moving the project forward.
The last step is to properly value the FNG assets before a purchase offer is made or a purchase price is agreed upon. Project value should not be based on the value it ultimately brings to the FNSB, i.e., the value of the benefit to the people of Fairbanks over time. That could be tens of millions of dollars. The value should be based on what a commercial entity would pay for FNG in an arm’s length economic transaction. Based on this type of analysis a reasonable purchase price for FNG can be negotiated.
Summary
First, any action the FNSB takes in support of any proposal to bring natural gas to Fairbanks should be made in the context of how it accomplishes the goal of providing long-term, low-cost energy to Interior Alaska. At every stage of the process, what is being proposed and evaluated should be evaluated in the context of how it increases the likelihood of accomplishing the goal of long-term low-cost energy for Fairbanks. Don’t lose sight of the goal.
Next, if the above analysis is followed, and after careful and thorough economic and public policy considerations, the trucking option is chosen as a viable option to pursue, and ownership of the entire integrated operation is required, and a reasonable economic/commercial price is negotiated, then it may be reasonable to proceed ahead with this venture. But, to move forward with a project without a thorough analysis through a well-defined process is shortsighted and could lead to poor decision-making and increased risk of failure of the project. The FNSB needs to complete a thorough review of the proposal through a well thought-out process before it gives the green light for AGPA to purchase FNG.
Monday, June 14, 2010
BP Gulf Oil Spill Response Plan Review
The gulf oil spill is now headed into its eighth week. Many have commented on the inaccuracies and weaknesses of the BP Oil Spill Response Plan, but few have analyzed it for what needs to be done to ensure the same results do not happen again. The plan is inadequate as it exists. BP’s Plan and all other plans like it need to be changed, and the state and federal agencies need to take this opportunity to collect additional information on performance of spill personnel and equipment to assist in the analysis of what is necessary to make future plans more effective.
The BP Oil Spill Response Plan is primarily an outline of the Incident Command structure, the responsibilities of the different members of the Incident Command Team, a listing of State and Federal Agencies that may need to be contacted in the event of a spill, incident forms, flow charts, decision diagrams, response organizations and equipment lists. It sounds like and is more of a resource manual that a response plan. It provides little assistance to the Incident Commander in determining what to expect for response times and effectiveness for deployed equipment or reaction of the oil to the environment.
The models upon which the spill plan is based were so inaccurate that they provided the Incident Commander with little or no understanding of when and where to expect the oil. They were woefully inadequate in assisting the Incident Commander in understanding the volume of the spill, the trajectory of where to look for the spill or the speed of the spill through the environment.
The models should be redesigned to provide more accurate projections now that there is actual data to compare. If the models are inconsistent with what happened, the models are wrong and they need to be changed to reflect reality. Even if the models are changed, they will still be wrong the next time, but they may not so grossly underestimate the speed and trajectory of the oil as to be useless to the Incident Command Team.
Only three pages of the 582 page spill plan are dedicated to a written analysis of the worst case scenario and much of that is merely an explanation of the scenario and a listing of the different response methods and their capacities to recover oil. An Incident Commander would find no assistance in this section of the plan on how to respond to the spill or what to expect from a spill of this magnitude.
There is little anywhere in the spill plan in the way of analysis to assist the Incident Commander in understanding what to expect from the response options he is provided. Equipment lists have nameplate capacities but no analysis of their effectiveness in the environment. Skimmers with nameplate capacities totaling 491,721 barrels per day are identified in the plan and give a false sense that they should be able to easily capture a spill of 250,000 barrels and remove it from the environment. But oil does not collect in one place waiting to be picked up, and nameplate capacities are not the same as effective rates.
Spill plan worst case scenarios should have estimations of how much oil is expected to escape into the environment; estimations of daily rates and how long will it take to contain and stop the spill from continuing; estimations of how much is being dispersed into the water column and how much is suspended in plumes in the water column. Of the oil collecting on the surface, the Incident Commander should have an understanding of how much will probably aggregate in sufficient quantities to be retrieved by mechanical skimmers and what percentage can be attacked with dispersants or burned? The Incident Commander should understand what percentage is escaping, the quantity of oil, the quality of the oil and when and where to expect the oil onshore.
BP needs to collect information regarding effective rates for deployment of its spill response equipment. For each piece of equipment deployed the following information should be collected:
1) the time required for equipment to be deployed onsite should be recorded, from the time it was requested to the time it was deployed onsite;
2) data should be collected regarding standby time for each piece of equipment, transportation time to get equipment to a new location for deployment, and time deployed in response to the spill;
3) during the time deployed the volume of liquid retrieved should be recorded, and data regarding the oil/water ratio should also be captured.
If this information is captured and analyzed it would provide the data necessary to calculate an effective response rate for each piece of equipment deployed. Effective response rates provide the Incident Commander with a more accurate tool than nameplate capacities in planning a response to a major oil spill.
Once the information has been collected from the spill it should be analyzed with the response team, state and federal agencies, and other stakeholders to determine the requirements for future offshore exploration and operations spill plans.
In addition, a plan that is only required to be updated once every two years is going to have a certain number of errors. I recommend annual updates and a certification by the person signing the plan as to the accuracy of the plan. That would require someone in the organization to attempt to verify all the numbers in the plan at least once a year.
Half of BP’s Incident Command Organization Chart did not have individuals identified to fill the incident command positions. I recommend that all leadership positions in the Incident Command structure should be identified in the organization chart and those individuals should be required to participate in a response drill at least annually.
If the above recommendations are followed, they won’t prevent incidents from occurring, but incident responders will have more effective tools to assist them in their response and they will be more prepared to respond to the incident.
Steve Porter is a former exploration permitting manager for a major oil company and was responsible for the preparation and approval of offshore oil spill response plans.
The BP Oil Spill Response Plan is primarily an outline of the Incident Command structure, the responsibilities of the different members of the Incident Command Team, a listing of State and Federal Agencies that may need to be contacted in the event of a spill, incident forms, flow charts, decision diagrams, response organizations and equipment lists. It sounds like and is more of a resource manual that a response plan. It provides little assistance to the Incident Commander in determining what to expect for response times and effectiveness for deployed equipment or reaction of the oil to the environment.
The models upon which the spill plan is based were so inaccurate that they provided the Incident Commander with little or no understanding of when and where to expect the oil. They were woefully inadequate in assisting the Incident Commander in understanding the volume of the spill, the trajectory of where to look for the spill or the speed of the spill through the environment.
The models should be redesigned to provide more accurate projections now that there is actual data to compare. If the models are inconsistent with what happened, the models are wrong and they need to be changed to reflect reality. Even if the models are changed, they will still be wrong the next time, but they may not so grossly underestimate the speed and trajectory of the oil as to be useless to the Incident Command Team.
Only three pages of the 582 page spill plan are dedicated to a written analysis of the worst case scenario and much of that is merely an explanation of the scenario and a listing of the different response methods and their capacities to recover oil. An Incident Commander would find no assistance in this section of the plan on how to respond to the spill or what to expect from a spill of this magnitude.
There is little anywhere in the spill plan in the way of analysis to assist the Incident Commander in understanding what to expect from the response options he is provided. Equipment lists have nameplate capacities but no analysis of their effectiveness in the environment. Skimmers with nameplate capacities totaling 491,721 barrels per day are identified in the plan and give a false sense that they should be able to easily capture a spill of 250,000 barrels and remove it from the environment. But oil does not collect in one place waiting to be picked up, and nameplate capacities are not the same as effective rates.
Spill plan worst case scenarios should have estimations of how much oil is expected to escape into the environment; estimations of daily rates and how long will it take to contain and stop the spill from continuing; estimations of how much is being dispersed into the water column and how much is suspended in plumes in the water column. Of the oil collecting on the surface, the Incident Commander should have an understanding of how much will probably aggregate in sufficient quantities to be retrieved by mechanical skimmers and what percentage can be attacked with dispersants or burned? The Incident Commander should understand what percentage is escaping, the quantity of oil, the quality of the oil and when and where to expect the oil onshore.
BP needs to collect information regarding effective rates for deployment of its spill response equipment. For each piece of equipment deployed the following information should be collected:
1) the time required for equipment to be deployed onsite should be recorded, from the time it was requested to the time it was deployed onsite;
2) data should be collected regarding standby time for each piece of equipment, transportation time to get equipment to a new location for deployment, and time deployed in response to the spill;
3) during the time deployed the volume of liquid retrieved should be recorded, and data regarding the oil/water ratio should also be captured.
If this information is captured and analyzed it would provide the data necessary to calculate an effective response rate for each piece of equipment deployed. Effective response rates provide the Incident Commander with a more accurate tool than nameplate capacities in planning a response to a major oil spill.
Once the information has been collected from the spill it should be analyzed with the response team, state and federal agencies, and other stakeholders to determine the requirements for future offshore exploration and operations spill plans.
In addition, a plan that is only required to be updated once every two years is going to have a certain number of errors. I recommend annual updates and a certification by the person signing the plan as to the accuracy of the plan. That would require someone in the organization to attempt to verify all the numbers in the plan at least once a year.
Half of BP’s Incident Command Organization Chart did not have individuals identified to fill the incident command positions. I recommend that all leadership positions in the Incident Command structure should be identified in the organization chart and those individuals should be required to participate in a response drill at least annually.
If the above recommendations are followed, they won’t prevent incidents from occurring, but incident responders will have more effective tools to assist them in their response and they will be more prepared to respond to the incident.
Steve Porter is a former exploration permitting manager for a major oil company and was responsible for the preparation and approval of offshore oil spill response plans.
Thursday, May 27, 2010
Evaluation of Exploration in the Arctic OCS
The BP oil spill in the Gulf of Mexico has affected and will continue to affect the environment and the lives of many in the southern coastal states for years to come. For Alaskans the spill brought back memories of Exxon Valdez oil spill in 1989 and the impact it had on their lives.
Today the BP oil spill has resulted in a more direct impact on Alaska and the future of oil and gas exploration in the State. Today President Obama announced the suspension of Shell’s offshore arctic exploration operation plans. There is substantial uncertainty regarding when and if the Administration will allow exploration in the Arctic OCS to continue.
The purpose of this article is to outline the issues that the Administration needs to address before they decide to allow or disallow exploration in the offshore Arctic.
In the weeks following the Exxon Valdez oil spill, as the exploration permitting director for a major oil company, I submitted my first offshore oil spill contingency plan. The issues we were required to address then are the same issues that should be addressed now as the Obama administration evaluates whether or not to make the suspension of offshore exploration drilling long term or permanent.
There are four areas that should be examined during the review: 1) formation pressures and risk, 2) safety and prevention, 3) spill plan preparedness, and 4) effectiveness of equipment and personnel.
First, formation pressures and the potential risk of blowout
The risk of encountering high pressure pockets of gas or oil should be understood and planned for in the drilling and well casing program. Several wells in the Arctic have lost well control due to encountering high pressure gas pockets that were not managed properly in the drilling program. Luckily none involved loss of well control in an oil producing zone. Even though there have been several loss of well control events, statistically the industry has done a good job understanding and preparing for this type of event.
Second, safety and prevention
In the event of the loss of well control, the operator should be able to utilize the safety mechanisms in place on the rig to stop the flow of oil or gas to the surface. The most well know mechanism, especially after the BP blowout, is the blowout preventer. Functioning properly, it should be able to seal off the well and allow the operator to develop a plan to regain control of the well without release of hydrocarbons into the environment. These safety mechanisms are tested regularly and almost always work. But there are now at least two well known events where they didn’t work: the IXTOC in Mexican waters, and now the BP blowout in the Gulf of Mexico OCS.
Third, spill plan preparedness
Shell has committed a substantial amount of equipment to meet the Alaska Department of Environmental Conservation’s Response Planning Standard and to meet the Minerals Management Service requirements. On paper Shell could handle a well blowout that discharged up to 5,500 barrels of oil into the environment for up to 34 days which is the number of days Shell projects it will take to drill a relief well and stop the blowout. On paper it looks like Shell has met the spill plan preparedness standard.
Fourth, effectiveness of equipment and personnel
The Oil Discharge Prevention and Contingency Plan (ODPCP) contains lists of equipment and nameplate capacities but very little analysis in the way of the effectiveness of that equipment in the environment the equipment will probably encounter.
Generally industry spill plans and presentations regarding preparedness make it look like they are prepared and could clean up oil in any environment they encountered in their operations. Pictures of spill response vessels and spill equipment in the Arctic environment give the audience the feeling that the equipment pictured will be onsite and ready to perform the function to the effectiveness that is listed on its nameplate.
The problem is that nameplate capabilities don’t work in the Arctic. Skimmers that performed poorly in the Gulf of Mexico will perform even worse in the Arctic, even if they are “winterized” for Arctic conditions. Sea ice conditions in the Arctic may prevent spill response vessels and equipment from getting close enough to the oil to deploy the equipment. Oil may be entrained in the ice and under the ice where spill response equipment will not be effective. Oil may not collect in sufficient quantities or may be weathered to such an extent that in situ burning is not an available option.
There is documentation of the amount of equipment available to respond to a spill and the potential response times, but there is little analysis of the effectiveness of that equipment in various arctic conditions. The State of Alaska and the MMS need to understand how much oil can be expected to be picked up under different scenarios and what the impact is on the environment from the remaining oil that is not recaptured.
How effective is the use of dispersants in broken ice conditions? What is the impact on wildlife in the water column and on the ice? Some of the dispersant will get on the ice. What if it is injested by wildlife? What would seem unusual for people is not always unusual or uncommon for animals. There is at least one incident on the north slope where a polar bear injested industrial liquids resulting in the death of the polar bear.
Exploration drilling activities are planned to begin on or about July 4th and drilling in hydrocarbon bearing zones would end on or before October 31st, depending on ice and weather. What if a blowout occurred late in the drilling season, or what if sea ice prevented the drillship from getting back on location? There may not be sufficient time to drill a relief well during that drilling season and the drillship may have to return the next summer drilling season to complete the relief well. If the existing drillship burns up in the ensuing fire, the relief rig will not be available to drill a relief well until the next drilling season. What is the impact on the environment from an uncontrolled well blowout that continues to release oil in the environment for 6 months or longer?
Shell’s exploration plan states that “A very large spill from a well-control incident is not a reasonably foreseeable event in connection with the OCS exploration activities set forth in Shell’s EP, and therefore, this EA does not analyze the impacts of such a worst-case scenario.” Lets hope they are right.
You don’t plan for meteors hitting the earth, but you do plan for earthquakes. The likelihood of a catastrophic oil spill in the arctic is somewhere in between the two.
If the state and federal government approve Shell moving forward in the Alaska OCS, they need to understand that a major oil spill from a blowout will not be easier to stop or clean up in the arctic than it was in the Gulf of Mexico. It will be more difficult. The best we can hope for is good management practices and the statistical likelihood that the incident will not occur.
Today the BP oil spill has resulted in a more direct impact on Alaska and the future of oil and gas exploration in the State. Today President Obama announced the suspension of Shell’s offshore arctic exploration operation plans. There is substantial uncertainty regarding when and if the Administration will allow exploration in the Arctic OCS to continue.
The purpose of this article is to outline the issues that the Administration needs to address before they decide to allow or disallow exploration in the offshore Arctic.
In the weeks following the Exxon Valdez oil spill, as the exploration permitting director for a major oil company, I submitted my first offshore oil spill contingency plan. The issues we were required to address then are the same issues that should be addressed now as the Obama administration evaluates whether or not to make the suspension of offshore exploration drilling long term or permanent.
There are four areas that should be examined during the review: 1) formation pressures and risk, 2) safety and prevention, 3) spill plan preparedness, and 4) effectiveness of equipment and personnel.
First, formation pressures and the potential risk of blowout
The risk of encountering high pressure pockets of gas or oil should be understood and planned for in the drilling and well casing program. Several wells in the Arctic have lost well control due to encountering high pressure gas pockets that were not managed properly in the drilling program. Luckily none involved loss of well control in an oil producing zone. Even though there have been several loss of well control events, statistically the industry has done a good job understanding and preparing for this type of event.
Second, safety and prevention
In the event of the loss of well control, the operator should be able to utilize the safety mechanisms in place on the rig to stop the flow of oil or gas to the surface. The most well know mechanism, especially after the BP blowout, is the blowout preventer. Functioning properly, it should be able to seal off the well and allow the operator to develop a plan to regain control of the well without release of hydrocarbons into the environment. These safety mechanisms are tested regularly and almost always work. But there are now at least two well known events where they didn’t work: the IXTOC in Mexican waters, and now the BP blowout in the Gulf of Mexico OCS.
Third, spill plan preparedness
Shell has committed a substantial amount of equipment to meet the Alaska Department of Environmental Conservation’s Response Planning Standard and to meet the Minerals Management Service requirements. On paper Shell could handle a well blowout that discharged up to 5,500 barrels of oil into the environment for up to 34 days which is the number of days Shell projects it will take to drill a relief well and stop the blowout. On paper it looks like Shell has met the spill plan preparedness standard.
Fourth, effectiveness of equipment and personnel
The Oil Discharge Prevention and Contingency Plan (ODPCP) contains lists of equipment and nameplate capacities but very little analysis in the way of the effectiveness of that equipment in the environment the equipment will probably encounter.
Generally industry spill plans and presentations regarding preparedness make it look like they are prepared and could clean up oil in any environment they encountered in their operations. Pictures of spill response vessels and spill equipment in the Arctic environment give the audience the feeling that the equipment pictured will be onsite and ready to perform the function to the effectiveness that is listed on its nameplate.
The problem is that nameplate capabilities don’t work in the Arctic. Skimmers that performed poorly in the Gulf of Mexico will perform even worse in the Arctic, even if they are “winterized” for Arctic conditions. Sea ice conditions in the Arctic may prevent spill response vessels and equipment from getting close enough to the oil to deploy the equipment. Oil may be entrained in the ice and under the ice where spill response equipment will not be effective. Oil may not collect in sufficient quantities or may be weathered to such an extent that in situ burning is not an available option.
There is documentation of the amount of equipment available to respond to a spill and the potential response times, but there is little analysis of the effectiveness of that equipment in various arctic conditions. The State of Alaska and the MMS need to understand how much oil can be expected to be picked up under different scenarios and what the impact is on the environment from the remaining oil that is not recaptured.
How effective is the use of dispersants in broken ice conditions? What is the impact on wildlife in the water column and on the ice? Some of the dispersant will get on the ice. What if it is injested by wildlife? What would seem unusual for people is not always unusual or uncommon for animals. There is at least one incident on the north slope where a polar bear injested industrial liquids resulting in the death of the polar bear.
Exploration drilling activities are planned to begin on or about July 4th and drilling in hydrocarbon bearing zones would end on or before October 31st, depending on ice and weather. What if a blowout occurred late in the drilling season, or what if sea ice prevented the drillship from getting back on location? There may not be sufficient time to drill a relief well during that drilling season and the drillship may have to return the next summer drilling season to complete the relief well. If the existing drillship burns up in the ensuing fire, the relief rig will not be available to drill a relief well until the next drilling season. What is the impact on the environment from an uncontrolled well blowout that continues to release oil in the environment for 6 months or longer?
Shell’s exploration plan states that “A very large spill from a well-control incident is not a reasonably foreseeable event in connection with the OCS exploration activities set forth in Shell’s EP, and therefore, this EA does not analyze the impacts of such a worst-case scenario.” Lets hope they are right.
You don’t plan for meteors hitting the earth, but you do plan for earthquakes. The likelihood of a catastrophic oil spill in the arctic is somewhere in between the two.
If the state and federal government approve Shell moving forward in the Alaska OCS, they need to understand that a major oil spill from a blowout will not be easier to stop or clean up in the arctic than it was in the Gulf of Mexico. It will be more difficult. The best we can hope for is good management practices and the statistical likelihood that the incident will not occur.
Monday, May 3, 2010
The Red Pen Challenge Update
This morning I called and left messages regarding the Red Pen Challenge at the following gubernatorial campaigns:
Ethan Berkowitz
Hollis French
Sam Little
Sean Parnell
Bob Poe
Ralph Samuels
Bill Walker
Donald Wright
If you know of a candidate for governor that is not on this list that would like to be included in the challenge, please ask them to contact me, or if you are one of the above candidates and somehow did not receive my message, please contact me as well. For the sake of convenience I have reprinted the Red Pen Challenge below.
I call this proposal The Red Pen Challenge.
I propose that every candidate for governor should review the capital budget and identify those items they would veto and submit them to the people of Alaska at the same time the Governor submits his signed capital budget bill, with appropriate vetoes if any, to the people of Alaska.
Rules of the Challenge
1) The governor agrees, in advance, to the date and time he will make public his decision on the capital budget.
2) Each candidate will submit their proposed capital budget to the public on the same date prior to the governor’s submittal to the public.
3) Governors Rules apply. – Each candidate will be required to provide the public with a copy of the budget with the specific “vetoed” items lined out and initialed, just like the Governor is required to do.
4) All newspapers will be encouraged to post on their web pages all responses so the Alaska public can compare the “decisions” of each of the participating candidates and add this information to their overall evaluation of who they want to support for governor.
I believe the above proposal will provide the appropriate scrutiny that was not applied during the legislative process to each and every appropriation in the capital budget.
Since the capital budget has not been transmitted to the governor there is still plenty of time for each of the candidates to comply with the above challenge. They will have the same amount of time to review and analyze the capital budget as the governor has.
I am also certain that if a candidate needs more information about the value of a specific appropriation, the recipient of that appropriation will be glad to provide the candidate with as much information as the candidate needs to make their decision.
I will be contacting each candidate and the governor over the next week to see who will be willing to rise to the challenge. The governor is the only candidate that will automatically participate because he is required by law to make a decision on the capital budget. The governor still needs to agree to a specific date and time when he will communicate his decision on the capital budget to the public.
I am looking forward to sharing their responses to the challenge in a future article.
Ethan Berkowitz
Hollis French
Sam Little
Sean Parnell
Bob Poe
Ralph Samuels
Bill Walker
Donald Wright
If you know of a candidate for governor that is not on this list that would like to be included in the challenge, please ask them to contact me, or if you are one of the above candidates and somehow did not receive my message, please contact me as well. For the sake of convenience I have reprinted the Red Pen Challenge below.
I call this proposal The Red Pen Challenge.
I propose that every candidate for governor should review the capital budget and identify those items they would veto and submit them to the people of Alaska at the same time the Governor submits his signed capital budget bill, with appropriate vetoes if any, to the people of Alaska.
Rules of the Challenge
1) The governor agrees, in advance, to the date and time he will make public his decision on the capital budget.
2) Each candidate will submit their proposed capital budget to the public on the same date prior to the governor’s submittal to the public.
3) Governors Rules apply. – Each candidate will be required to provide the public with a copy of the budget with the specific “vetoed” items lined out and initialed, just like the Governor is required to do.
4) All newspapers will be encouraged to post on their web pages all responses so the Alaska public can compare the “decisions” of each of the participating candidates and add this information to their overall evaluation of who they want to support for governor.
I believe the above proposal will provide the appropriate scrutiny that was not applied during the legislative process to each and every appropriation in the capital budget.
Since the capital budget has not been transmitted to the governor there is still plenty of time for each of the candidates to comply with the above challenge. They will have the same amount of time to review and analyze the capital budget as the governor has.
I am also certain that if a candidate needs more information about the value of a specific appropriation, the recipient of that appropriation will be glad to provide the candidate with as much information as the candidate needs to make their decision.
I will be contacting each candidate and the governor over the next week to see who will be willing to rise to the challenge. The governor is the only candidate that will automatically participate because he is required by law to make a decision on the capital budget. The governor still needs to agree to a specific date and time when he will communicate his decision on the capital budget to the public.
I am looking forward to sharing their responses to the challenge in a future article.
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