Nothing New in Obama Plan for Offshore Drilling

In early April, the Obama Administration announced that it will expand offshore exploration and development to reduce dependence on foreign oil. The plan that was announced is, in fact, more restrictive than what was already in place, and will have no near- or mid-term impact on our need to import oil. It maintains the status quo by allowing leasing in the eastern Gulf of Mexico and offshore Virginia, and by allowing drilling in certain areas offshore Northern Alaska, but it closes the Bristol Bay area offshore southern Alaska. All areas in the Pacific Ocean off the coasts of California, Oregon and Washington remain closed.

The portion of the eastern Gulf of Mexico that is offered for leasing in the government’s plan is limited to areas more than 125 miles offshore that are mostly in water depths of 6,000 feet or greater (Figure 1). While the administration describes this as a development area, it is a high-risk, ultra deep-water wildcat province. Sixty-two wells were drilled in shallower areas of the eastern Gulf before the drilling moratorium, and the only prospective area found so far is the shallow-water Destin Dome region off the Alabama coast where reserves are estimated to be 2.7 trillion cubic feet of gas (equal to about 1.5 months of US natural gas consumption). The geology of the eastern Gulf of Mexico is different from the traditional producing area of the central and western Gulf. While it contains legitimate petroleum systems, it is a relatively high-cost, high-risk area.

The area of the Atlantic coast that is included in the government plan is offshore Virginia (Figure 2). The Atlantic margin of the U.S. was drilled and evaluated before the area was closed to exploration in the 1980s, and the results were dismal. More than 50 wells were drilled, and only a few wells in the Baltimore Canyon area off the coasts of New Jersey, Maryland and Virginia had any indications of petroleum. A few wells tested showed that natural gas could be produced at rates that would probably be commercial onshore today, but not 100 miles offshore.

In frontier areas like the Atlantic Margin and Eastern Gulf of Mexico, big fields are commonly discovered early in the exploration cycle because industry identifies and drills the largest, most obvious features first. The fact that approximately 50 largely unsuccessful wells have been drilled in each of these areas is discouraging. The Atlantic Margin seems to be an area where any hydrocarbons that are found will be natural gas rather than crude oil, based on geochemical analysis to date. While that is not a completely negative factor, further exploration there does little to change our dependence on foreign crude oil, and we currently have abundant supplies of onshore natural gas that can be found and developed at considerably lower cost.

On the positive side, the Atlantic Margin and eastern Gulf of Mexico are huge areas where important discoveries may have eluded early exploration efforts. Neither of these regions has been evaluated using modern seismic methods that could yield a different view of its potential for producing natural gas or oil.

As someone who works in the exploration and production business, I am in favor of opening these areas and letting industry decide if they have merit. At the same time, it is important to be objective. Under the most favorable scenario, it will take many years to acquire and interpret the necessary seismic and geochemical surveys that precede drilling. If discoveries are made, appraisal drilling, economic analysis, and development planning will require more time. Infrastructure adds yet another layer of time and complexity. Evaluation of large oil and gas projects worldwide commonly takes at least six years from discovery to first production. High-risk, capital intensive oil and gas exploration cannot be expected to produce quick results.

100 Years of Natural Gas Supply from Shale? It’s More Like 6 Years.

The widespread belief that there is 100 years of natural gas supply in the U.S. because of shale plays is incorrect. The Potential Gas Committee (PGC) estimated 1,836 Tcf of technically recoverable gas resources for the U.S. in its report released in June 2009. Along with proved reserves of 238 Tcf, there are 2,074 Tcf or 85 years of total supply based on current demand of 25 Tcf per year (EIA). The contribution of shale gas is 661 Tcf, or about one-third
of the total, technically recoverable resource (Figure 1). The PGC estimate of probable resource volume is 441 Tcf, or about 18 years of supply. Shale gas accounts for one-third of that amount, or 147 Tcf, which is about 6 years of supply at current U.S. demand. That is a lot of gas, but far less than the volume that is routinely stated in the press or by shale-gas advocates. These public statements often do not take high decline rates or anticipated future demand growth into account.

ExxonMobil’s Acquisition of XTO Energy: The Fallacy of the Manufacturing Model in Shale Plays

See the original full post on The Oil Drum:
http://www.theoildrum.com/node/6229

Posted by aeberman on February 22, 2010 - 8:26am
Topic: Geology/Exploration
Tags: exxonmobil, natural gas, original, shale gas, xto energy [list all tags]

Most analysts believe that the ExxonMobil acquisition of XTO Energy (XTO) represents a dramatic shift in strategy by the premier exploration and production (E&P) company, and a validation of shale plays. It is neither. The move represents a considered and deliberate choice that acknowledges diminished opportunities for the oil giant to add and replace reserves. The acquisition acknowledges that natural gas is the only viable short-term solution to North America’s energy needs, and that demand will grow. It implies that ExxonMobil believes that higher natural gas prices will be part of that energy future. It presumes that the company can improve on the flawed manufacturing model that has dominated the way that U.S. shale plays have been pursued.

ExxonMobil’s acquisition of XTO only seems dramatic to those who have not paid attention to the company’s strategy and change in project mix over the past decade. Its portfolio consisted of 75% unconventional resources before the XTO acquisition (Figure 1) with a strong emphasis on tight, acid and sour gas, LNG, and heavy oil projects. Tim Cejka, President of ExxonMobil Exploration Company, told The Wall Street Journal last year that his company has been “bullish” on shale plays since 2003 (Wall Street Journal, July 13, 2009). David Rosenthal, ExxonMobil Vice President of Investor Relations recently said, “It’s not a strategic shift” (Houston Chronicle, February 2, 2010).

See the rest of the original full post on The Oil Drum:
http://www.theoildrum.com/node/6229

Implications of Exxon Mobil acquisition of XTO Energy Presentation February 2010

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Implications of Exxon Mobil acquisition of XTO Energy Presentation February 2010

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McMoran Davy Jones Gas Discovery

Arthur E. Berman and Joshua H. Rosenfeld

McMoran Exploration Company has made a significant discovery in the U.S. Gulf of Mexico that may contain 2-6 trillion cubic feet (Tcf) of natural gas reserves. The well was drilled in 20 ft of water 10 miles south of the Louisiana coast on South Timbalier Block 168 (Figure 1). The discovery by McMoran (operator) and partners Plains Exploration & Production Company and Nippon Oil Corporation is very deep (28,125 to 28,262 feet drilling depth) but with excellent quality gas-saturated reservoir rock in the upper Wilcox Sandstone (Paleocene-Eocene--135 ft of gas pay with as much as 20% porosity and 10-20 ohm-meters of resistivity).

The Davy Jones well was drilled on a large anticlinal feature with approximately 20, 000 acres of structural closure at Wilcox level (Figure 2). McMoran intends to continue drilling another thousand feet or so in order to evaluate the next two potential reservoir strata known as the lower Wilcox “Whopper Sand” and the Cretaceous Tuscaloosa Sandstone (Figure 3). The Tuscaloosa is a prolific producing reservoir onshore.

The discovery is especially important because it provides a link between onshore Wilcox production and a series of discoveries from equivalent strata in the deep-water Gulf of Mexico including the Tiber Field announced by BP in September 2009. In 2001, the announcement of a Wilcox discovery in Unocal’s deepwater Trident-1 (Perdido) well came as a complete surprise to most of the industry. Since then, these reservoir sands have been found in a 300-mile long and 50-mile wide fairway parallel to the present-day shelf margin beneath 5,000 to 10,000 feet of water, containing more than 20 fields. The stratigraphy of the undrilled gap between the onshore and the deepwater Wilcox under the coastal plain and continental shelf of Texas and Louisiana, however, has remained conjectural. This “down dip” Wilcox play has been ignored by drillers until McMoran’s test because structural complexity and deep targets involve high risk, expensive exploration.

Recent discoveries of oil and gas in the deep-water offshore region of the Gulf of Mexico may have recoverable resources of up to 15 billion barrels of oil equivalent. Reservoirs consist of Paleocene to Eocene submarine fan and turbidite sandstones whose thickness exceeds 1000 feet. This sequence has been correlated with the onshore Wilcox Group. The considerable thickness, and wide areal extent of the deep-water offshore Wilcox interval challenges the common perception that most sandstone in the Wilcox was deposited within shelf and upper continental slope environments with only thin, channelized sands reaching the deep basin within shale-dominated turbidites.

For the last decade, curious geologists have struggled to explain the counter-intuitive presence of hundreds of feet of massive Wilcox sand across a wide swath of the Gulf of Mexico so far from the contemporaneous shoreline, and whether this sand trend is continuous from the onshore into the deepwater (Berman and Rosenfeld, World Oil, June, 2007). Conjecture also swirls around whether the Wilcox extends southward and underlies Mexico’s deepwater and shelves.

The news from the Davy Jones well appears to open an important new gas play in the Gulf of Mexico. McMoran’s findings will undoubtedly encourage more deep drilling for Wilcox targets in this trend. Meanwhile, the next 1,000 feet in the Davy Jones well may yet reveal the highest quality reservoir sands that correlate with the basal Wilcox “Whopper Sands” in the deepwater.

Some analysts have said that this discovery proves that concerns about peak oil and gas are unfounded. This is common whenever important discoveries are announced. It is, therefore, worthwhile to place the Davy Jones discovery in the context of broader petroleum supply, demand, cost and timing factors. While 2 Tcf is a lot of gas, it is about equal to one month of U.S. consumption during peak winter months, and we currently have an over-supply of natural gas that may persist for some time.

It is worth mentioning that the announced discovery is based on sketchy information from well logs and is does not represent an actual flow test. The reason for this incomplete data is the extreme depth, pressure and temperature of the Wilcox reservoir in this well.

Bottom-hole pressures may be as high as 25,000 pounds per square inch, by far the highest pressures known in Gulf of Mexico wells, and almost 10 times the rocket engine chamber pressure required for spacecraft liftoff. While not specifically mentioned, reservoir temperature is probably considerably more than 400 degrees Fahrenheit. Gas has never been produced at these temperatures and pressures, and may be present engineering obstacles. In addition, gas reserve volumes will shrink at surface conditions. There is also a possibility that the gas will contain carbon dioxide, which will reduce the volume of commercial gas and present a disposal problem.

The Davy Jones well has cost almost $200 million so far, and development drilling is expected to cost $1.5-2.0 billion. Production facilities will add to that cost. There are few rigs in the world that are capable of drilling at these depths and temperatures, so Davy Jones will have to stand in line with all of the deep-water Wilcox discoveries in the Gulf of Mexico and the pre-salt fields in Brazil’s Santos Basin for rig availability. The earliest estimates for first production are in 2013.

At the same time, the apparent discovery opens a new trend in the Gulf of Mexico that could contain considerable new reserves. The Davy Jones discovery announcement comes at a time when few oil and gas companies are pursuing objectives other than shale plays. Fortunately, there are wildcatters that are willing to pursue these high-risk, high-reward plays, this time with apparent success. Stay tuned because this is a promising development.

The Data That We Cannot Get

I would like to clarify what I mean about operators not showing their data.

Anonymous says that there is no data to show because we only disagree about how to project existing data. That is partly true, but some of the rebuttals to our work dispute the reliability of Texas Railroad Commission production data for the Barnett Shale play. They claim that they have "other data" that somehow leads them to different conclusions, but will not show it.

That's a really interesting tactic that I remember from the elementary school playground as "I know something you don't know".

I think that questioning Railroad Commission data is a red herring since production taxes and royalty payments are based on what operators report to the Commission. Those who claim that this data is no good imply that operators are improperly reporting production to the state. I would very much like people that doubt the reliability of Railroad Commission data take this issue to one of the Commissioners.

Beyond the "data" issue is the larger question of how the operators and financial advisory companies arrive at such high reserves. I can reproduce these high reserves by using absurd hyperbolic exponent b values, no terminal decline rate, or no economic limit.

When I use group vs. individual well-decline methods and b factors somewhat greater than 1.0, I can get to higher average EURs (more detail on this in a few days) than what I have published, though these reserves are still marginally commercial. Since I assume the integrity of the people who claim reserves that are 50-100% more than my most generous projections, I would like to understand how they reach those reserves.

In addition, we have always cautioned that without pressure data that only operators have, we may be too pessimistic in our EUR projections. Decline-curve analysis is only a part of the EUR evaluation process. Other factors include calculating a drainage area and running reservoir simulations to match production history with reservoir properties. These require data that we cannot get.

Operators are not required to report water production to the state of Texas. Water disposal can be a considerable cost, and the onset of water production may result in catastrophic production rate decline. This is data that we cannot get.

Some readers point out the current decline rates are much lower that we predict in some cases. This may be true because of the frequent workovers and re-fracs done in the out years of many shale years. In order to evaluate the result of lower decline rates due to human intervention, we need to know the cost. This is data that we cannot get.

Some operators claim that natural gas liquids provide uplift to their Barnett Shale economics. NGLs are not reported to the state because they are separated during gas treatment and processing in a plant. Only operators know the volume of NGLs and the gas shrinkage that results from their extraction. This is data that we cannot get.

While it is true that much of the EUR debate focuses on how to project future production from exiting data, it is hardly the entire story. A respectable EUR does not necessarily mean that the well is commercial.

From Perry Fischer, former World Oil Editor

November 5th, 2009

When I got up this morning, I decided not to pack my usual snack lunch--I thought that it would be my last day. I was right--I was fired.

On Oct 22, I received two emails forwarded to me via the World Oil Circulation Department. They were from DS and KR at two Houston oil and gas companies, and they both said that they were canceling their free subscriptions due to Art Berman's columns on shale plays. DS went further by faxing and then phoning to the president his feelings about Art Berman.

Let me be clear: The decision to pull Art's column was due to pressure from these two companies.

The next day, the president stopped by to tell me that we had to stop Art from writing about shale plays.

I said, "I'm surprised that there haven't been at least a dozen complaints. I've seen worse on other topics."

It was no use arguing. Ironically, I had already decided that Art should take a break from the shale plays for a while anyway, just because he was running out of new things to say, having written 8 (I'm guessing) columns on that one subject.

It was the 23rd of October and we usually have all of the columns in by the 15th of the month, but we have been so understaffed--just myself and 1.5 other people (we share one)--that we are now often late. So I called Art to see where he was at on his column. I quickly realized that Art's mind, and some of the work, were already committed. He felt that he owed it to his readers to comment on some of the recent rebuttals to his positioins on shale plays, so I decided that we'd go ahead and print what he had for the November issue.

Again ironically, Art agreed that going forward he was going to take a break from the shale topic, mostly because as he put it, "I'm not sure what more I can say."

Immediately after I hung up the phone with Art, the Publisher walked in, slapped down a fax from DS, and said, "We've got to stop Art from writing about these shale plays, we're getting too many complaints!"

I replied that I was aware of the complaints and said that the president was just in to discuss it, but that it was too late in the cycle to stop the November column but, in December, we would take "a little break." He said "Fine."

Normally, the magazine would be going out the door by then, but insufficient staff in both Editorial and Production departments caused further unforeseen delays. On Nov. 2, the magazine had been shipped, the "bluelines" were back (proof sheets), and they were about to go to press; we were minutes from being done done, when the Publisher walked in and said we had to pull Art's column.

I said, "I can't, I won’t; it’s finished, plus, we agreed that we'd leave November alone."

He said that it wasn't his decision, and that I was welcome to talk it over with the President, which I did. That conversation went nowhere. In his mind, there had been too many complaints (2), including 2 phone calls, and the column had to be pulled.

After three protests, including the fact that it would delay printing, I finally said, "This is a really bad decision, the best thing that you could do is nothing; there is no compelling reason to pull this; just let it go to press; the idea that we can please all of the people all of the time is impossible, unless we are careful to say nothing, print pabulum."

Obviously, I lost that battle. The last thing that I wanted to do Monday night (along with the Production Department person) was to write a quick column to replace Art's in two and-a-half hours; it was a step down in quality from his, and betrayed an incredibly thin skin on the part of World Oil management. I certainly would never have pulled it. A spineless Editor isn't an Editor at all.

It's important to know that Art left voluntarily. The decision was his alone. In my opinion, he was pissed. But then, if I worked my ass off on a good column, asked my friends for their counsel, opinion, and proofing, had the editor question a graph and ended up changing it, and then had it pulled and just set aside for the crummiest of reasons... well, I'd be pissed off too. If Art had stayed, he would have been under a magnifying glass. It's like breaking a pencil in half and then trying to put it back together.

I got through the night, emailed/talked to Art, and took two days of vacation. A minor brouhaha ensued on this blog and elsewhere and, when I returned, I was fired. I wasn't told why. Neither was I surprised.

In my 11 years at World Oil, I tried to take the "trade" out of "trade journal." The current management is trying to put it back in. Increasingly, decisions are being made for the sake of advertising. Unfortunately, the last vestige of “the separation of church and state,” meaning, between corporate and editorial, is gone. The marketing folks have won. Dilettantes’ meddling in day-to-day operations is now the norm.

I dare say that the last President, RM, who was summarily fired in April without explanation (so that's how he felt!), would have handled the situation much more deftly. (By the way, when you fire a president, aren't you supposed to trade up? I'd bet that not one employee feels that that is the case). But RM was old school (probably why he was fired). And so am I. My field experience and physics background will probably make me the last editor of World Oil with a technical background; part of a line of technically qualified Editors going back decades.