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Recently there have been several proposals from the legislature and others suggesting the State of Alaska should get in the oil and gas exploration business in Cook Inlet and possibly other areas of the State.
Although the idea has a good sounding ring to it, there are some basic assumptions behind the idea that are flawed. The most important assumption is that if the state gets in the exploration business it will find economic reserves of oil and gas for its dollars. The problem is that the most common sounding ring from an exploration well is hollow – a dry hole. The people of the State of Alaska are not prepared to spend millions of dollars exploring for gas merely to find out the state drilled a dry hole.
The reason companies are not spending money on exploration in Cook Inlet is the area is a mature basin from an exploration standpoint. Most of the major structures have already been explored. Normally this is the time when smaller independent companies come into a basin and explore the smaller structures. The difficulty in Alaska is that the cost of drilling the smaller structures is still too expensive for most independents. So Cook Inlet is caught in a position that the structures that are left aren’t worth the time for the large companies and they are still too expensive for the smaller companies.
The legislature has tried credits, lower taxes, and other incentives to encourage exploration in Cook Inlet, but no amount of incentives, short of providing actual cash, (not recommended) will encourage a company to do something that is not economically and geologically logical. Maybe someday, if an explorer can get a better price for their gas or if additional markets open up, we might see an active exploration program in Cook Inlet, but not before.
A response should do more than just throw water on someone else’s idea. A response should also provide guidance and direction, an alternative to the ideas it believes won’t work. So here is my recommended alternative.
1) Work with state regulatory agencies to approve contracts that allow gas to be sold to the utilities at a more economic (higher) price. Higher gas sales prices might stimulate additional exploration in the Cook Inlet basin.
2) Make sure Cook Inlet is prepared to participate in the large gas line open seasons. Fund ANGDA to hold an open season on a spur line so that Cook Inlet gas purchasers can participate in the large gas line open season. If Cook Inlet gas users do not participate in the large gas line open season, then Cook Inlet will still not get gas from the North Slope even if the large gas line is successful.
3) Encourage the legislature to deal with the two remaining issues that stand in the way of a successful large gas line open season: review the current gas tax and make appropriate changes if necessary and provide fiscal stability through developing a rational long term fiscal plan and budget process. I have addressed both of these issues in previous blogs.
4) Solve the Point Thomson issue so that Point Thomson development can move forward. I have talked about this in previous blogs as well.
5) The administration should meet with the North Slope Borough and the Alaska Eskimo Whaling Commission to understand and address their concerns regarding offshore development. If consensus can be reached, approach Congress for Alaska’s fair share of OCS revenue. If consensus can’t be reached, keep trying. Alaska should only approach Congress for Alaska’s fair share as a unified voice that both supports offshore development and requests Alaska share of that revenue.
6) Ditto Bristol Bay. Sit down with the commercial fishermen, native leaders, and other interested residents and understand their concerns. See if there are options available that would lead to offshore development with their support.
7) Review the economics of heavy oil on the North Slope to make sure the current tax structure is not stifling development.
8) Review exploration on the North Slope to see if exploration is properly incentivized. Oil exploration on state lands has the same problem on the North Slope as it does in Cook Inlet. It is a mature basin from an oil exploration standpoint and exploration will gradually shift to the independents. NPRA and the state and federal offshore are a different matter. They still hold great potential, and given the right incentives and support the state could see more exploration in these areas.
9) Dream big but plan rationally. Always leave the door open for discovery of new large deposits of economically recoverable oil and gas reserves, but don’t plan your budgets around that success.
The alternatives I recommend will not change the viability of Alaska's natural resource development overnight, but they will increase the likelihood of a strong oil and gas exploration and development industry in the future.
Tuesday, February 23, 2010
Sunday, February 21, 2010
Resource Potential of the Alaska North Slope
The Department of Energy, National Energy Technology Laboratory published a report titled “Alaska North Slope Oil and Gas A Promising Future or an Area in Decline in August 2007. The NETL recently published an Addendum to the Report. The report has often been quoted and used as a basis for projections of future oil and gas potential of Alaska’s North Slope.
The report is helpful in evaluating the prospectivity of certain areas of the North Slope as compared with other areas. For example, onshore state lands between the Colville and the Canning rivers and State Beaufort Sea, (basically all state lands on the North Slope) represent only ten percent (10%) of the future economically recoverable oil potential on the North Slope. Ninety percent (90%) of all future economically recoverable oil potential will be discovered on lands not owned by the state: twenty-one percent (21%) will be discovered in NPRA where the state will receive a production tax but no royalty; forty-seven percent (47%) will be discovered on the federal OCS lands where the state receives no royalty or production tax; and twenty-two percent (22%) will be discovered in ANWR where it is unknown what the state’s revenue percentage will be.
The state fares slightly better in the future economically recoverable gas potential. State onshore lands between the Colville and the Canning rivers and State Beaufort Sea represents almost twenty-five percent (25%) of all future economically recoverable gas potential on the North Slope. Seventy-five percent (75%) of all future economically recoverable gas potential will be discovered on lands not owned by the state: Twenty-two percent (22%) will be discovered in NPRA where the state will receive a production tax but no royalty; fifty-one percent (51%) will be discovered on federal OCS lands where the state receives no royalty or production tax; and a small percentage of gas may be found in ANWR where it is unknown what the state’s revenue percentage will be.
While the relative prospectivity of each area may be important to understand, the reality of what may be found in each area will be quite different. The NETL has modeled the potential for each area, not what they project will be discovered in each area. Figure 3-55 on page 3-107 of the report illustrates the production forecast for oil if the NETL’s “optimistic assumptions” (their term) are accurate. What the chart shows is current production will remain relatively flat for the next 10 years followed by a substantial increase in production until production peaks in 2042 at 3,000,000 barrels per day. This would mean the current oil pipeline would be at peak capacity and the state would have built a second pipeline to accommodate the additional production. This is based on NETL’s projection of the discovery of 35 to 36 billion barrels of oil. Obviously there is a very low chance of this occurring.
Figure 3-56 on page 3-108 of the report illustrates the production forecast for gas if NETL's "optimistic assumptions" are accurate. These optimistic assumptions of the discovery of 137 tcf of gas would have the state producing 11 bcf of gas per day by 2032 which would require all expansions by compression of the proposed 4.5 bcf per day gas pipline and then looping of that line. This too is a virtual pipe dream.
Many believe that the 137 tcf referred to in the NETL report will be discovered and produced over the next 50 years. In fact, they believe the potential is much greater. The only way to ground that belief in reality is to examine what they must also believe about the oil potential that was referred to in the same report. If they believe the 137 tcf will be produced, then they must also believe the 35-36 billion barrels of oil will be produced and that the existing TAPS pipeline will once again be at full capacity and an additional oil pipeline will be build to transport the surplus oil that has been discovered. The absurdity of such a position becomes apparent once it is understood in context.
Hopefully the above perspective will bring a bit of reality and understanding to the discussion of the oil and gas potential on the North Slope. The state should be an advocate for the oil and gas potential on the North Slope, but it should base its economic and business decisions on a more realistic analysis of North Slope potential. It is one thing to dream about winning the lottery, it is another thing to base your current business decisions on that assumption.
The report is helpful in evaluating the prospectivity of certain areas of the North Slope as compared with other areas. For example, onshore state lands between the Colville and the Canning rivers and State Beaufort Sea, (basically all state lands on the North Slope) represent only ten percent (10%) of the future economically recoverable oil potential on the North Slope. Ninety percent (90%) of all future economically recoverable oil potential will be discovered on lands not owned by the state: twenty-one percent (21%) will be discovered in NPRA where the state will receive a production tax but no royalty; forty-seven percent (47%) will be discovered on the federal OCS lands where the state receives no royalty or production tax; and twenty-two percent (22%) will be discovered in ANWR where it is unknown what the state’s revenue percentage will be.
The state fares slightly better in the future economically recoverable gas potential. State onshore lands between the Colville and the Canning rivers and State Beaufort Sea represents almost twenty-five percent (25%) of all future economically recoverable gas potential on the North Slope. Seventy-five percent (75%) of all future economically recoverable gas potential will be discovered on lands not owned by the state: Twenty-two percent (22%) will be discovered in NPRA where the state will receive a production tax but no royalty; fifty-one percent (51%) will be discovered on federal OCS lands where the state receives no royalty or production tax; and a small percentage of gas may be found in ANWR where it is unknown what the state’s revenue percentage will be.
While the relative prospectivity of each area may be important to understand, the reality of what may be found in each area will be quite different. The NETL has modeled the potential for each area, not what they project will be discovered in each area. Figure 3-55 on page 3-107 of the report illustrates the production forecast for oil if the NETL’s “optimistic assumptions” (their term) are accurate. What the chart shows is current production will remain relatively flat for the next 10 years followed by a substantial increase in production until production peaks in 2042 at 3,000,000 barrels per day. This would mean the current oil pipeline would be at peak capacity and the state would have built a second pipeline to accommodate the additional production. This is based on NETL’s projection of the discovery of 35 to 36 billion barrels of oil. Obviously there is a very low chance of this occurring.
Figure 3-56 on page 3-108 of the report illustrates the production forecast for gas if NETL's "optimistic assumptions" are accurate. These optimistic assumptions of the discovery of 137 tcf of gas would have the state producing 11 bcf of gas per day by 2032 which would require all expansions by compression of the proposed 4.5 bcf per day gas pipline and then looping of that line. This too is a virtual pipe dream.
Many believe that the 137 tcf referred to in the NETL report will be discovered and produced over the next 50 years. In fact, they believe the potential is much greater. The only way to ground that belief in reality is to examine what they must also believe about the oil potential that was referred to in the same report. If they believe the 137 tcf will be produced, then they must also believe the 35-36 billion barrels of oil will be produced and that the existing TAPS pipeline will once again be at full capacity and an additional oil pipeline will be build to transport the surplus oil that has been discovered. The absurdity of such a position becomes apparent once it is understood in context.
Hopefully the above perspective will bring a bit of reality and understanding to the discussion of the oil and gas potential on the North Slope. The state should be an advocate for the oil and gas potential on the North Slope, but it should base its economic and business decisions on a more realistic analysis of North Slope potential. It is one thing to dream about winning the lottery, it is another thing to base your current business decisions on that assumption.
Saturday, February 20, 2010
DNR Point Thomson Study Evaluated by Feds
Recently the National Energy Technology Laboratory (NETL) published an addendum to its August 2007 report titled “Alaska North Slope Oil and Gas, A Promising Future or an Area in Decline?” This report is often referred to by the State of Alaska and others for support in identifying the potential undiscovered reserves on the Alaska North Slope.
The April 2009 addendum made few changes to the original April 2007 Report, but one significant addition was the inclusion of a couple of paragraphs referring to Point Thomson. I have included the additional paragraphs below. The quote is from page 2-30 of the report and can be found at http://www.netl.doe.gov/technologies/oil-gas/publications/AEO/ANS_Potential.pdf.
The statement is significant because it evaluates a study commissioned by the Alaska Department of Natural Resources (ADNR) estimating the original oil and gas in place at Point Thomson and, I assume, is at least part of the reason for ADNR’s position arguing that Point Thomson oil is economic and should be produced first, prior to gas development. The federal report states that the DNR study was optimistic and that a more realistic reserve estimate would be approximately one-fifth the size stated in the DNR study.
Quote at Page 2-30
“Point Thomson is a large field, with a long and troublesome history. A study, recently commissioned by the ADNR (ADNR, 2008), provided an original gas in place (OGIP) estimate of 8.5 to 10.4 TCF, with original condensate in place of 490 to 600 million barrels of condensate (MMBC), and OOIP of 580 to 950 MMBO in the oil rim. The study suggests that under ideal conditions, with gas cycling and extended production of condensate and oil prior to gas blowdown (30 years with 22 producing wells and 8 injection wells), the field could produce as much as 420 to 515 MMBCF and 290 to 475 MMBO. The technically recoverable gas reserves produced under a scenario similar to the one above would be about 5.9 to 7.3 TCF. If blowdown were to occur early in the history of the field development, the models suggest that recovery of condensate and oil could be as low as 127 to 156 MMBC and 30 to 150 MMBO, but gas recovery would be in the 6 to 7 TCF range over a period of 12 to 15 years (ADNR, 2008). Additional scenarios were run with varying numbers of producing and injection wells, for periods of 10 and 20 years before blowdown, and results shown production ranges of: (1) 10 years of cycling – 300 to 370 MMBC, 225 to 370 MMBO, and 4.8 to 5.9 TCF, and (2) 20 years of cycling – 370 to 450 MMBC, 250 to 400 MMBO, and 4.8 to 5.9 TCF.
The findings appear to be optimistic and open to question, especially with respect to the recovery predicted for oil from the oil rim. The summary of findings (ADNR, 2008) cites the oil having American Petroleum Institution (API) gravity as high as 18°. This is the same range of API gravity as the heavy oil being produced from the West Sak and Schrader Bluff reservoirs, and recoveries are not projected to be more than 5 to 10%. The API gravity at the Kuparuk West Sak pool ranges from 22° to 10°, increasing with depth (temperature) and at the Milne Point Schrader Bluff pool it ranges from 22° to 16°. Thus a more realistic value for the oil rim at the Point Thomson field may be 58 to 95 MMBO, not the 290 to 495 MMBO theorized in the PetroTel study performed for ADNR. The Point Thomson owners “don’t believe the recovery of this heavy oil will be more than 5% --- nowhere near 50” (PN, 2008). They further state that “the oil rim is thin, discontinuous, and heavy oil --- molasses.””
The above bolding was mine and not in the original report. Additional discussion consistent with the above can be found at pages 3-98,99 where the NETL calls the ADNR study "overly optimistic."
The April 2009 addendum made few changes to the original April 2007 Report, but one significant addition was the inclusion of a couple of paragraphs referring to Point Thomson. I have included the additional paragraphs below. The quote is from page 2-30 of the report and can be found at http://www.netl.doe.gov/technologies/oil-gas/publications/AEO/ANS_Potential.pdf.
The statement is significant because it evaluates a study commissioned by the Alaska Department of Natural Resources (ADNR) estimating the original oil and gas in place at Point Thomson and, I assume, is at least part of the reason for ADNR’s position arguing that Point Thomson oil is economic and should be produced first, prior to gas development. The federal report states that the DNR study was optimistic and that a more realistic reserve estimate would be approximately one-fifth the size stated in the DNR study.
Quote at Page 2-30
“Point Thomson is a large field, with a long and troublesome history. A study, recently commissioned by the ADNR (ADNR, 2008), provided an original gas in place (OGIP) estimate of 8.5 to 10.4 TCF, with original condensate in place of 490 to 600 million barrels of condensate (MMBC), and OOIP of 580 to 950 MMBO in the oil rim. The study suggests that under ideal conditions, with gas cycling and extended production of condensate and oil prior to gas blowdown (30 years with 22 producing wells and 8 injection wells), the field could produce as much as 420 to 515 MMBCF and 290 to 475 MMBO. The technically recoverable gas reserves produced under a scenario similar to the one above would be about 5.9 to 7.3 TCF. If blowdown were to occur early in the history of the field development, the models suggest that recovery of condensate and oil could be as low as 127 to 156 MMBC and 30 to 150 MMBO, but gas recovery would be in the 6 to 7 TCF range over a period of 12 to 15 years (ADNR, 2008). Additional scenarios were run with varying numbers of producing and injection wells, for periods of 10 and 20 years before blowdown, and results shown production ranges of: (1) 10 years of cycling – 300 to 370 MMBC, 225 to 370 MMBO, and 4.8 to 5.9 TCF, and (2) 20 years of cycling – 370 to 450 MMBC, 250 to 400 MMBO, and 4.8 to 5.9 TCF.
The findings appear to be optimistic and open to question, especially with respect to the recovery predicted for oil from the oil rim. The summary of findings (ADNR, 2008) cites the oil having American Petroleum Institution (API) gravity as high as 18°. This is the same range of API gravity as the heavy oil being produced from the West Sak and Schrader Bluff reservoirs, and recoveries are not projected to be more than 5 to 10%. The API gravity at the Kuparuk West Sak pool ranges from 22° to 10°, increasing with depth (temperature) and at the Milne Point Schrader Bluff pool it ranges from 22° to 16°. Thus a more realistic value for the oil rim at the Point Thomson field may be 58 to 95 MMBO, not the 290 to 495 MMBO theorized in the PetroTel study performed for ADNR. The Point Thomson owners “don’t believe the recovery of this heavy oil will be more than 5% --- nowhere near 50” (PN, 2008). They further state that “the oil rim is thin, discontinuous, and heavy oil --- molasses.””
The above bolding was mine and not in the original report. Additional discussion consistent with the above can be found at pages 3-98,99 where the NETL calls the ADNR study "overly optimistic."
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