Showing posts with label API. Show all posts
Showing posts with label API. Show all posts

Thursday, November 10, 2011

OGPSS - A review of North American future production

This is a good point to recap the intent of the current series of OGPSS articles. Internally, this marks the end of the segment that has dealt with North American oil and natural gas production. The series is not an in-depth review of individual fields but rather seeks to paint a broad background against which to judge the realities of the coming changes in the global supply:demand balance. More detailed discussions are provided by the excellent analysis of such folks as Jean Laherrère, who is even now examining in more detail the production records from the wells in the deep waters of the Gulf of Mexico.

Perhaps more critically, it comes when there are increasing indications that the investment being placed on renewable energy around the world as a replacement for fossil and nuclear power generation might not be adequate to meet the need. For example, this week the British Institution of Mechanical Engineers has pointed out to the Scottish Parliament that their renewable targets for 20% total energy and 100% of electricity production by 2020
did not appear to be supported by a rigorous engineering analysis of what is physically required to achieve a successful outcome in the timescale available.
It is relatively easy for politicians to promise that energy supply is adequate into the foreseeable future. Euan Mearns, for example, has repeatedly written, and guest hosted articles on The Oil Drum which show that supply requires infrastructure and planning over many years, without which (and the absence is evident) those promises become not only unrealistic, but also unattainable.

Just as I wrote this, the White House announced that the decision on the Keystone pipeline would be postponed until after the election next year. In a sense the Administration view echoes the opinion of one of those opposed to the pipeline:
“It’s not like we’ll have an oil shortage,” said Mark Lewis, a partner at the law firm Bracewell & Giuliani who specializes in oil and gas pipelines. “We’ll continue to get product from the sources we get product from.”

If Canadian tar-sands oil moves to Asia, Lewis said, then the U.S. would just continue getting its oil from regions like the Middle East. And the Canadian oil sands would most likely still be developed, with that product entering the same global market.
This series is testing the truth of those remarks and that opinion by looking at the realities of future production and the oilfields that it will come from. As mentioned above, this began with a look at the resources of North America, and it is time to review what was found.

When this series began last April it set out to look at the potential future changes in the North American oil and natural gas supply there were three different parts to that supply. The first is the historic oil, that coming from existing wells and fields, often coming from stripper wells around the country. Then there were the supplies from fields that are currently being developed, and where production is continuing to rise, such as in the Bakken fields of North Dakota and Montana. And then there is the potential that will come from finding and developing new fields in the relatively near term. Perhaps as an indication of my own “Oops” moment, I used the Energy Plan proposed by Governor Perry to illustrate the potential future additional fossil fuel that might be available over the next two decades. That was very similar in promises to a Wood MacKenzie Report prepared for API, and released in September. To give my comments on those projections, I will look first at the summary of projected increase in oil production from that report. This is divided into two parts, the first assumes that current policies continue, and it sees energy supply growing as follows:

Total US Production – using current conditions. (Wood Mackenzie )

The plot shows an increase in oil production from 2010 to 2030 of some 1.2 mbd, which in the overall scheme of things is not really that much change from the present over the twenty year time interval (0.7% per year). Natural gas, on the other hand is expected to rise some 14.4 bcf/day (1.2% per year) which is a little more impressive.

However, if all the wishes of the industry were to come to pass, (the development policy case) then Wood Mackenzie sees considerable potential for supply growth.

Production with an accelerated development program (Wood Mackenzie )

In that developed condition Wood Mackenzie sees oil production increasing 7.6 mbd to 15.4 mbd by 2030, while natural gas production rises by 36.8 bcf/day to 96.9 bcf/day.

The first concern that I have with these plots is that of the declining reserve. In previous posts I have discussed various estimates for the decline in production that occurs in existing wells over time. This occurs with both oil and natural gas wells, and changes with rock type, well type and other factors. For example a recent post by Fractracker on the performance of 756 Marcellus wells notes that horizontal gas wells declined an average of 39% in the last year, while vertical wells declined 47.6%, though those numbers do not reflect wells that were closed because they were no longer producing (16.7% of the horizontal wells and 6.9% of the vertical wells). Figures from other gas shales have reported decline rates in the Haynesville, for example, of 85%. In conventional oil wells (and reservoirs such as the Bakken are, for this discussion, considered as unconventional) the decline rates now lie above 5% . What this means for US production is that, just to stay even, the industry has to add at least 360,000 bd of new production each year, to maintain a roughly 7.2 mbd level of total oil production. (and that is likely to be, at best, the average gain in production over the next ten years from the Bakken and Niobrara combined).

So where does Wood Mackenzie see the gains in production from the “development” case?

Regions where additional production may be obtained (Wood Mackenzie )

The problem that the map shows is that much of the new discovery and development is anticipated to come from the offshore, whether it is East Coast, West Coast, Gulf of Mexico or Alaska. In comments on the post discussing drilling off the Atlantic coast, my quote on it taking four to ten years for production following the start of leasing led to kindly admonishment by Art Berman, Harry Flashman and Rockman on the overly optimistic view that this represented, with the reality of development being more likely to occur over decades. This holds even more true for resources off the Alaskan coast, where the on-land infrastructure is not currently in place. And it fails to recognize the antagonism that state governments (such as those I mentioned from New Jersey) have to offshore drilling on both coasts.

The current increase in oil production in the United States is, in part, due to the development of long horizontal wells, with multiple fractures along those wells to improve flow to economic levels from shales that were previously uneconomical to drill. As long as enough production can be achieved from such wells to keep them viable for the oil industry they will be developed. When they cease to be then they won’t. The rapid decline rates that are found for these wells (as was shown in the posts on Bakken and Niobrara) mean that as production moves from the sweeter spots in the reservoirs out to the leaner fringes, a point will be reached, in a few years, where those economic factors will come into play. As that time approaches the price of oil (for a variety of reasons) will be sufficiently higher than it is today to encourage greater overall production than might be anticipated from today’s figures, but it will be nowhere near enough to meet the levels of US demand. And it will still curtail overall production.

The gain in production that Wood Mackenzie sees in moving to the “development phase” does not really kick in, were all things to come to pass, until about 2016. And even then the main initial gains are assumed to come from the easing of regulations, which is, I rather suspect, a wish, rather than any reflection on what might realistically happen.

Possible gains in future production over the current condition (Wood Mackenzie )

The delay in granting permission for the Keystone pipeline will shift some 700 kbd of US supply out another year at least. But that does bring up the issue of the oil sands. They are the one source where the deposit size is known and adequate, and where gains to help meet demand could be achieved. However, with the delay and possibly even denial of the pipeline, it is now quite possible that the Canadian Government and the other parties concerned might hear again the same blandishments from China that persuaded the Turkmen, and when we finally get around to giving grudging permission for Canada to sell us more oil, that additional tar sand oil may already be heading overseas through pipelines running west.

Whether, at that point, we can then
continue to get our oil from regions like the Middle East
is a point that I will look at as this series continues, and we start to examine the long term potential of sustained oil supply from regions overseas.

Oh, and a quick P.S. for those who remember the post on the Alaskan pipeline, in August it was running at an average of 538,623 bd, with the annual average now running at 568,471 bd.

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Posted by Heading Out at 9:59 PM 1 comments
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Friday, September 16, 2011

A gentle cough for CBS and the National Petroleum Council

I was flipping through the news channels last night and came in on the tail end of a CBS story about billions of barrels of oil in Texas. Having missed the introduction, it was not until this morning that I discovered that it was a story about the Eagle Ford Shale.
Energy companies are rushing to the area to tap deposits that could produce up to 12 billion barrels of oil, and enough natural gas to power every American household for at least five years.

By 2020, that number (of new jobs) is expected to increase to 66,000.
I remember writing a short post on the Eagle Ford last December pointing out that the field was currently being more actively developed in the “wet gas” region where the Natural Gas Liquids (NGL) content is high, since this was more profitable than the deeper “dry gas” sections. But I did not remember the numbers being that high.

Being curious about them, a check at the EagleFordShale Web site suggests that the CBS report was triggered by a report from the National Petroleum Council, which was released yesterday. That report had been requested by Energy Secretary Chu to
reassess the North American natural gas and oil resources supply chain and infrastructure potential, and the contribution that natural gas can make in a transition to a lower carbon fuel mix . . . . .(provide) advice on policy options that would allow prudent development of North American natural gas and oil resources consistent with government objectives of environmental protection, economic growth, and national security (and) the United Sates sees a future in which valuable domestic energy resources are responsibly produced to meet the needs of American energy consumers consistent with national, environmental, economic and energy security goals, ... [and the United States] has the opportunity to demonstrate global leadership in technological and environmental innovation. Accordingly, I request the Council’s advice on potential technology and policy actions capable of achieving this vision.
The report notes that “The United States and Canada together produce 4% more oil than Russia, the world’s largest producer.”

Leading World Oil Producers (NPC using BP Statistical Review).


Further, together with Canada, the report points out that the United States produces over 25% of global natural gas production, with the arrival of shale gas being the game changer that may provide over 100 years of supply at today’s demand rates.

Leading World Natural Gas Producers (NPC using BP Statistical Review)

Yet it is in the discussion of those reserve numbers that the shaky timber on which the NPC case is build becomes apparent. When discussing future oil production it notes:
One source is tight oil, found in geological formations where the oil does not easily flow through the rock, such as in the Bakken formation of North Dakota, Saskatchewan, Montana, and Manitoba. Tight oil has also benefited from technologies similar to those used for shale gas, including hydraulic fracturing. Over the next 20 years, tight oil production could continue to grow. A second potentially large supply source is in new offshore areas, particularly in the Gulf of Mexico and the Atlantic and Pacific coasts of the United States and Canada. Access to and potential development of these new U.S. areas would require an Executive Branch level directive to include such areas in the 2012–2017 Leasing Program. New offshore areas could provide both natural gas and oil in significant quantities to supplement the continuing strong production in the Gulf of Mexico. Third, new Arctic oil and natural gas supply have a potential of the equivalent of over 200 billion barrels of oil. This is in addition to existing oil supply and proven natural gas reserves on the Alaska North Slope. The new Arctic resources could yield significant supply after 2025. Fourth, another very large long-term oil supply source lies in the shale oil deposits of Colorado, Utah, and Wyoming. The development of these billions of barrels of oil from these new resource areas will require sustained investment, substantial advances in technology, and environmental risk management systems and approaches.
The report also supplies this estimate of the available natural gas, showing several estimates.

Estimates of the Technically Recoverable Natural Gas Available in the United States. (NPC )

I have recently written of the Bakken Shale, and the problems that I see with its long term production. I have also similarly discussed some of the problems with the Arctic development and the potential size of the reserves available. ) In the later case I noted that the recent USGS report had downgraded, as an illustration, their initial estimate of 10 billion barrels of oil being technically recoverable from the National Petroleum Reserve, to a current estimate of 500 million barrels of economically recoverable oil. That percentage difference between the actual recoverable, relative to the technically recoverable is in line with a 6.9% estimate of the economically recoverable (relative to technically) volumes of natural gas, which I pointed out when I reviewed the EIA Shale Gas report.

If one were to look at these numbers in that light (though the actual detailed resource section with its break down is not yet available from NPC) then the numbers become more credible. Unfortunately it makes the estimates of the contributions that the industry will make to national energy security and job creation a whole lot weaker, if the numbers are only one-twentieth of those which are currently being thrown around.

Unfortunately the report goes on to spend much more time discussing the environmental aspects of oil and gas recovery, and emphasizing such things are the reduction in pad size in the Arctic:

Change in Arctic Pad Size with Improved Technology (API

There is not that much that is encouraging in the way of new technology that is anticipated to come on line to increase the percentages of natural gas and oil that can be recovered, and the report does comment on the need for more graduates as the current work force retires – a need that is not being adequately filled.

It is a weak straw on which to build the projections that CBS used.

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Posted by Heading Out at 11:36 AM 2 comments
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Tuesday, January 18, 2011

API and some thoughts on America's Energy Future

There seems to be a little drop in the intensity of the debate over the arrival of Peak Oil. Given that crude oil prices are hovering around $100 a barrel, and quite likely to go higher over the course of the year, it is perhaps only the recent history of oil at $147 a barrel that stops a more intense debate. After all we have been there - done that, before so why worry? Unfortunately this may be the lull before the storm.

Consider that there has been a change or two, even in the short period of time since our last visit to this price range. Last time it was possible to see an increase in production from places such as the United States, and from Russia. Not huge amounts, but symbolic, that production could respond, somewhat to a potentially more expensive product. But this time around it is likely that we will see both United States and Russian production fall this year, even as prices rise. And with a certain complacency evident in the politicians, whose constituents are now paying higher prices for product, things that might be properly done to at least help out, are not seen as that important at the moment.

The API addressed this issue, at the beginning of the year, through the speech of Jack Gerard, their President. Looking at the “State of American Energy”, he was able to point to the number of new jobs that the industry has been able to create both with the development of the Marcellus gas shales in the East, and with the Bakken developments in the North West. He also pointed to the $95 million in taxes, rents, royalties and bonus payments that the Treasury gets from the industry each day. The totality of current jobs was counted as 2.1 million directly employed in the oil and gas industry and 7.1 million in the affiliated industries that work to support it.

Yet, as he noted,
Over the past few years, revenues to the U.S Treasury from lease sales have decreased, due in part to a lack of opportunities.

Our industry is eager to initiate new projects. But without an adequate level of business certainty, with concerns about policies that might curtail this industry’s ability to access new resources, those projects might never get off the drawing board
Part of that uncertainty comes from the changes in regulation that will control drilling offshore from the United States. Some rigs that could have continued to drill in the GOM, but were halted after the Deepwater Horizon disaster have now moved abroad, and may be gone years before they return to American prospects. But until there is a clear commitment to facilitating American production, that exodus may well continue. The severity of the coming crisis is still not evident in the eyes of the politicians and the general public. Further, as the price of oil rises, it is assumed that the wealth of the companies producing the oil is also increasing, and so (despite rising costs that are not mentioned nearly as often) it is assumed that companies can afford higher payments. And with new quarterly and annual profit statements coming out soon, it is going to be a little difficult to defend that position against what is quite likely to be a set of overall record, or close to record, earnings. Even BP had returned to profit at the end of the 3rd Quarter of 2010.

The fact that they are playing in a shrinking sandbox, as producing countries take over more and more of the profit generating parts of production is not seen as a concern.. Yet, as we have seen in places such as Venezuela, the results of government involvement is quite often to reduce the level of investment in the industry, just as investment costs should, in reality, increase to allow discovery and development of the more difficult reserves that will be needed in the future.

As the Venezuelan experience shows “Twenty billion here, and twenty billion there, and soon they are talking real money,” (to misquote Senator Dirksen). And yet those monies are likely to be inadequate to properly develop the resources of that country. Jack Gerard seems the future in the further development of the gas shales, in increasing production from the Canadian oil sands, and in the development of a significant oil shale industry.

At the present there is too much natural gas available for the growth of the gas shale industry to be assured over the next five years. This is not because of the problems that are being stirred up over the chemistry of the fracking fluids, nor the ability of the companies to properly protect the ground water around the sites, those issues have realistically been solved decades ago, and the furor will die away in time. The problem at the moment relates more to the cost of developing the reserves at a time when the market has natural gas available that is cheaper than can be extracted from some of the gas shale wells. And as long as that holds true the industry is unlikely to grow much.

One thing that API did not mention much in the speech, but which came later, in one of Jane Van Ryan’s blog posts, is a valid concern over the march toward E15, that is the use of 15% ethanol in gasoline. That original target was predicated on the assumption that, by now, cellulosic ethanol would be at or close to large-scale commercial production. Well that has not proved to be the case. EPA backed off a little on the targets last year, as Robert Rapier noted at the time. More recently he has drawn attention to the failure of the Range Fuels plant in Soperton GA , which is now closing. After spending $320 million, and producing one batch of ethanol, the company needs more money to solve technical issues.

As far as the national target is concerned:
Congress initially set 100 million gallons as the 2010 target for cellulosic biofuel, but the EPA cut that to 6.5 million gallons. It appears that the industry might have produced less than 1 million gallons last year, reported ClimateWire on Tuesday, citing an estimate by a government analyst.
(On the other hand Valero is moving ahead with plans to invest $50 million in the Mascoma plant in upstate New York, that move will include the purchase of just under a million barrels of cellulosic ethanol) .

That decline is now, however, the concern expressed by API. Among other issues, there are two problems that higher concentrations of ethanol in the mix may cause that are not necessarily that evident. The first is that those of us who use small engines for mowers, chain saws, trimmers etc may find these running unexpectedly hot if they use the new mix. And albeit the manufacturers warn against its use, most of us fill the can while we are refueling the car, and from the same pump.

The other concern relates to the seals in tanks and underground storage.
Just as there are seals in gaskets in cars that can be affected by E15, similar seals and gaskets can be found at the service station and the pump above the ground and the underground storage tank. The DOE recently released some test results of gas station dispensers and the results were pretty sobering. About 70 percent of the older equipment in existence failed these tests and about 30 percent of the new equipment failed these tests. That is a real liability concern because if you are a service station owner and have to determine whether to use E15 in an existing underground storage tank when the replacement costs for that storage tank could be $50,000 to $200,000. The testing that the DOE did was only above ground.
If that weren’t enough – since we won’t have much cellulosic ethanol, we’re going to have to rely on corn. And what is the story on the price of corn? March prices are $6.59 a bushel, and still rallying.
Output in the U.S., the world’s largest grain exporter, dropped 4.9 percent last year, leaving supply before the 2011 harvest at the lowest in 15 years, the Department of Agriculture said last week. The agency also cut its forecast for global inventories to 127 million metric tons, the lowest since 2007.

“Prices have not risen high enough to slow demand,” said Greg Grow, the director of agribusiness for Archer Financial Services Inc. in Chicago. “The attitude among consumers is that you have to buy the breaks to accumulate tightening inventories.”
I guess one of the interesting questions becomes as to whether we will see $5 a gallon gasoline in 2011 or 2012?

Of course we could talk of alternate investments in geothermal, the less popular renewable. But maybe I’ll hold off on that for another day.

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Posted by Heading Out at 11:32 PM 5 comments
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Wednesday, March 31, 2010

API, EPA and Hydrofracking gas shale

There has been some ongoing discussions around the country about the possibility of drinking water contamination as a result of hydrofracking natural gas wells, most particularly those that would be placed in the Marcellus shale, which, in part, underlies sections of New York state which provides the watershed for New York City. And to put this in context, it should be born in mind that hydraulic fractures are generally relatively short, and occur in the shale at depths of thousands of feet, while ground water is usually obtained from wells that are less than 500 ft deep.

I first mentioned this at the time of the House hearing on the topic and have returned to the topic intermittently over the past few months as the issue had been dragged more and more before the public. I have also covered the basic technology behind hydrofracking natural gas wells, including direction to a video which illustrates how hydrofracking improves production and makes the well productive. And there is a Primer on the subject (that includes the composition of a typical fracking fluid).

Well a couple of weeks ago the EPA announced that they were going to conduct a study of the process. More precisely:
The U.S. Environmental Protection Agency (EPA) announced that it will conduct a comprehensive research study to investigate the potential adverse impact that hydraulic fracturing may have on water quality and public health. Natural gas plays a key role in our nation’s clean energy future and the process known as hydraulic fracturing is one way of accessing that vital resource. There are concerns that hydraulic fracturing may impact ground water and surface water quality in ways that threaten human health and the environment. To address these concerns and strengthen our clean energy future and in response to language inserted into the fiscal year 2010 Appropriations Act, EPA is re-allocating $1.9 million for this comprehensive, peer-reviewed study for FY10 and requesting funding for FY11 in the president’s budget proposal.
One wonders, given the input from the state agencies at the Congressional Hearing, who said, since they have been doing most of the monitoring for the past several decades, that there wasn’t a problem, who will provide the research study, and who will be doing the peer-review? But perhaps I am being a little cynical so early in the process.

With all that as background, last Thursday the American Petroleum Institute (API) held a phone conference for a number of those of us who blog on energy, so that we could ask questions on hydrofracking from a group of industrial experts.

API had previously noted that EPA had already carried out such a study in 2004, although that one dealt more specifically with hydrofracking coal seams to extract coal bed methane. That study had concluded:
Based on the information collected and reviewed, EPA has concluded that the injection of hydraulic fracturing fluids into CBM wells poses little or no threat to USDWs and does not justify additional study at this time.
It should be noted that that coal seams are typically quite significantly shallower than a typical gas shale, generally by several thousand feet.

And since I haven’t defined an underground source of drinking water (USDW), let me do that by quoting that earlier EPA document:
A USDW is defined as an aquifer or a portion of an aquifer that:
A.1 Supplies any public water system; or
2. Contains sufficient quantity of groundwater to supply a public water system; and
i. currently supplies drinking water for human consumption; or
ii. contains fewer than 10,000 milligrams per liter (mg/L) total dissolved solids (TDS); and
A. 1. B. Is not an exempted aquifer

NOTE: Although aquifers with greater than 500 mg/L TDS are rarely used for drinking water supplies without treatment, the Agency believes that protecting waters with less than 10,000 mg/L TDS will ensure an adequate supply for present and future generations

API noted, both then and at the conference call, that hydrofracking is an integral part of much of the oil and gas industry, and has been for over sixty years, during which time there have been over a million wells that have used the technology.

The transcript of our conversation is now available on the web and I am only going to summarize portions of it, since the full transcript runs to 21 pages. I’ll also add the odd comment of my own.

The experts fielded by API to talk with us were:
Sara Banaszak, Senior Economist
John Felmy, Chief Economist
Stephanie Meadows, Senior Policy Advisor
Erik Milito, the Group Driector for Upstream/Industry Operations
Richard Ranger, Senior Policy Advisor
Andy Radford, Senior Policy Advisor

Jane Van Ryan of API acted as Moderator, and had invited me to join the others in the conference.

Gail Tverberg (representing TOD) opened the discussion by asking about the fate of all the fluids that were used in generating the hydrofrack, which can run from hundreds of thousands, to millions of gallons. Stephanie Meadows answered that most of the water comes back out of the ground, though it may take weeks or months to recover most of the fluid, (Richard Ranger noted that the fractures that are generated don’t typically extend that far – the distance is usually measured in feet,) and recovery rates can range from 30 – 70% of the fluid injected. The rest can slowly trickle out during production, but can remain, within the producing formation until then.

(This was something that I had wanted clarifying and in the three questions I had submitted before the conference, I asked about the risk of various shales being water sensitive. The concern being that if the water in the fracking fluid is in contact with the shale, for a significant time, it can wet and weaken certain shale to the point that it can soften and deform – which would prematurely close the fractures and lower the volume produced, both as a rate and total amount. You can 
inhibit the wetting by adding different polymers (as they do when 
dealing with, for example, the Gumbo shale in Texas when they drill
 through it using a water-based mud), and if I remember the ones that they often use are also used to
 keep the froth in beer from collapsing.)

Jazz Shaw (The Moderate Voice) mentioned that there continue to be repeated claims (he cited one from Maurice Hinchey a Congressman from New York, who claimed on a recent CNN program that there were multiple cases of groundwater from hydraulic fracturing, and refused to acknowledge that the host pointed out that the claim could not be substantiated – which followed a similar comment that I had noted that arose from the state agencies that currently monitor hydrofracking operations when they testified before Congress). It was also pointed out that the Ground Water Protection Council had also been unable to find any instances of this occurring.

Erik Molito pointed out that over the million wells that had been hydrofracked, while there had been some surface spills (which were not defended) there was not one instance where a hydrofrac in the formation had led to groundwater contamination, over the 60-years that the practice has been in existence. At present 90% of current natural gas wells that are drilled are hydrofracked. It is not only practiced in shale, one of my questions related to use in Colorado, where I was told that
Virtually every well 
drilled into the tight Cobell sandstone of the Wattenberg field in the
 Weld County area, or into the Williams Fork sands of the Mesa Verde group 
in the Piceance Basin on the Western Slope involves hydraulic fracturing 
for well completion. HF is also used in a substantial amount of the coal
bed methane production in the San Juan Basin in the southwest part of 
the state.
In later discussion it was also pointed out that Colorado requires that the ingredients in the fracking fluid formation be listed, but not the specific amounts or recipes. (In much the same way that Coke lists the ingredients but not the formula, so that no-one can gain the commercial benefit of copying their recipe). Other states also follow that requirement.

Richard Ranger pointed out that as a protective measure increasingly drillers are working with state agencies to take water samples both before and after drilling and fracking the wells to substantiate the claims of no impact. He also noted that the state agencies work closely together through groups such as the Interstate Oil and Gas Compact Commission to ensure that the wells that are drilled are properly monitored, and that nothing is done without following a detailed permitting process. And knowledge gained, for example in Texas, is quickly transferred to Pennsylvania.

When it came to the impact of any proposed regulation, asked by Rich Trzupek of Big Journalism, the Economists on the panel noted that up to 60% of current natural gas production comes from hydrofracked wells, and that slowing or stopping that amount of natural gas would obviously have significant impact. And it was noted that natural gas increasingly provides a fall-back reserve of power should the wind not blow, or the sun not shine, to support renewable energy supplies. (And in a subsequent follow-up API has pointed to the jobs that could be gained by growing the natural gas industry to get natural gas from the Marcellus shale in Pennsylvania .

Tim Hurst of Ecopolitology raised the question of the EPA project, and he was assured that, at the appropriate time API would have a response.

Gail asked about the source of the water, and in response Richard Ranger noted that while a typical 7 – 10,000 ft well might use 3 million gallons of water, this is the amount used by a typical golf course in a week, a 5-acre cornfield in a season, or a municipality of 8 million people(e.g. New York City) in 4 minutes. The amount of water required to generate a million Btu’s from natural gas is about 10% of that required to produce the same amount from coal, and about 0.1% of that required to get the same amount of energy from corn-based ethanol.

Geoff Styles of Energy Outlook asked about the use of diesel, but it was pointed out that while this is sometimes used as the basis for drilling fluids and muds, where water based muds might create problems in reacting with the rock, diesel is not used in the hydrofracking process.

One of the possible risks of hydrofracking was posited as being that the fractures would intersect other wells drilled in the same location, but Andy Radford pointed out that the degree of control ensures that fractures are grown under tight enough control, and limited ranges, to ensure that this does not happen, and that when wells are spent, that the sealing of the well is done sufficiently well to ensure that there is no risk of subsequent leakage,

The conference went on for over an hour, so I would recommend that those interested in more detail review the entire transcript. It was, as I have tried to illustrate, quite informative.

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Posted by Heading Out at 11:38 PM 3 comments
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Friday, February 27, 2009

The OCS, Chevron and an API Conference

Every so often the American Petroleum Institute (API) hosts a conference call for interested bloggers to talk to folk in the industry. Today they had Gary Luquette who has been President of Chevron North America Exploration and Production Company since 2006. He was in Washington to testify before the House Committee on Natural Resources, and copies of his opening statement were available. This was my first visit to one of these events, and I am grateful to Jane Van Ryan for the invitation. The transcript won’t be out until next week, and I did not catch the names of other participants that well, so I will put that information up when I get it. The questions were focused largely on the testimony, which dealt with access to the outer continental shelf (OCS) of the United States, to allow drilling and production of oil and gas. (API has also just released a primer on the topic.) It is a region where access is currently not available, and so in a sense this was perhaps a move towards the “drill, baby, drill” rhetoric of the last election. The current areas that are off limits are shown on this map that I borrowed from the API primer.

Source API
UPDATE I will add links to the posts of the others that were in the call as I get them, and at the bottom of the post.

Some of the most productive recent discoveries have occurred in the deep waters of the OCS in the Gulf of Mexico, (for example Thunder Horse at 250,000 bd, and the Chevron Tahiti project. The region falls under the Minerals Management Service of Interior, and they recently published their 2008 review of the region. Currently their purview includes the gridded bit of the map below, and the report contains detailed information on wells and production in that region. For example the following figure shows how, over time, companies have had to go to deeper and deeper waters to find new reserves, but that in doing so that they are finding larger fields.
Source MMS
Average field size in the GOM showing discovery date and depth of water (Source MMS ).

It is this trend in discoveries that were an underlying part of the message that Chevron (and the other companies) were trying to convey. As Gary pointed out in his response to a question from “The Bear”, the assumption in the 1960’s, based on MMS surveys, was that the deepwater Gulf would hold 6 – 8 billion barrels of oil, and to date more than 45 billion barrels have been found. Thus estimates, such as an overall yield of only 200,000 bd from new discoveries, are likely to be considerably too low, and his estimate is that production could ramp up to over 1 mbd. New technologies are continually being evolved to deal with the challenges of producing oil from the increasingly more complex reservoirs that are being found, and thus current estimates of ultimate production are likely to be considerable underestimates when oil finally starts to flow. Staying on message relative to current Administration (and national) priorities, he pointed to the increase of over 160,000 jobs that just granting access could bring as this development moved forward. (Though it takes a long time to bring this all to pass, bear in mind that Tahiti was found in 2002, and is expected to come on line at 125,000 bd this year). The ultimate revenue to the government was projected at over $1.7 trillion.

Geoff Styles of Energy Outlook asked about the impact of the current estimate of tax changes (Pick Points 44) which Gary responded to by pointing out that the tax changes were still just a proposal, and while he felt that they were in the wrong direction and more of a challenge in the current climate (Geoff thinks the timing is wrong for cap and trade, he was optimistic for the future.)

Someone from Copious Dissent asked about the impact of climate change, obviously a current hot topic, and Gary responded that you have to accept that there is a perception in the minds of the people, and these for a time create a reality you have to live with. And that, at the moment, is where the climate change situation lies.

He went on to answer another question on AGW and corporate profits by noting that the scale of investments that the company must make each year (around $22 billion) requires that they generate large amounts of capital, and even as profits fall with the price drop for oil, they must continue to invest that amount if they were to have a future. (Tahiti, for example, cost $6 billion and they have yet to earn a penny on the investment).

Steve Rhodes of the Republican Temple asked about possible gas taxes, and the possibility of taxing folk per mile driven. The API position on this has been that taxes are not opposed, as long as they go for the support of infrastructure, but that this would be a very regressive tax, and since it will include a GPS element also carries elements of Big Brother. (My own sense on this is that it is already a dead issue).

Gail (the Actuary at TOD) has already a post up today on the impact of taxes on the industry and was curious as to the impact of proposed legislation on the smaller producers, particularly for the natural gas industry. She then went on to ask as to how $40 oil, and $4 (per mcf) gas prices would impact production. Gary pointed out that it wasn’t too long ago that those would have been very good numbers, and that, were it not for production costs which have recently gone up dramatically, the industry would be happy to work in that environment. Since prices are up it has brought a number of projects closer to the margin of profitability. But with open access to the OCS (which was the underlying message of the call) the industry could live and profit with those prices. He was less definitive in regard to gas production, admitting that while $4 might work in some rich shales, others would need $8 to be viable.

In regard to a small question I had on biofuels (since it was included in his opening statement) he felt that these were already making an impact, mentioned the food vs fuel dilemma, and that they were working with Weyerhauser on generating fuel from wood products.

On a more general note Gary closed by noting that last year the gap between possible supply and demand dropped from 4 mbd to 2 mbd. While current demand in the US is down because of the recession, and will likely continue so, in the rest of the world demand is likely to continue to grow, so that overall production needs to keep up. When the recession ends, then growth, particularly in countries like China and India will return to double digits, with the equivalent increases in demand, and we must be ready to meet that.

Well those are my notes from the conference call. Again my thanks to Jane and API for the invite.
UPDATE: Others who posted on the call are:
Bob McCarty

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