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So the anticipated decline sets in. But is it by underinvestment (low prices) or geological? It would be interesting what effect this may have on synthetic oil production from the much touted Tar sands.
Thats the $64,000 (per megajoule) question. If prices head back up how much production comes back online??
OilmanBob and I just discussed the following related to the Barnett and Fayetteville Shale Gas Plays in AR/TX.
Looks like EnCana thinks there's one in B.C.-
http://www.dogwoodinitiative.org/newsstories/bc-beckons-oilandgas
"You just know that when they pay that kind of money, they've got something," he said. "That's good for us. Our geologists tell us that the potential resource from shale gas is 250 trillion cubic feet, and that's just in B.C. Even if we recover just a portion of that, it's huge."
The two areas of interest are the Horn River Basin, which Mr. Neufeld says is the largest shale gas play in Canada, and the Cordova Embayment. In 2007 alone, companies have spent $40-million on leases in Cordova and $240-million over two years on leases in Horn River.
Gas trapped in shale is not a new resource, it has been overlooked in Canada in the past because it is difficult to produce compared with gas from other types of reservoirs. But significant volumes of natural gas are produced from gas shales in the United States.
"It's huge because it's shale," said Vic Levson, assistant executive director in the resource development and geoscience branch, Ministry of Energy Mines and Petroleum Resources. "It's a completely new target.
"Five years ago people would have laughed you off the street if you said there'd be a huge land sale in shale."
This quote right here stands out:
"You just know that when they pay that kind of money, they've got something," he said. "That's good for us. Our geologists tell us that the potential resource from shale gas is 250 trillion cubic feet, and that's just in B.C. Even if we recover just a portion of that, it's huge."
The same was said in Arkansas. Reality has set in here.
Very limited potential in a small area of the Total Potential. And if gas doesn't go to $10, progress on that
will be measured.
Arkansaw of Samuel L Clemens
powder river basin (wyoming) coal gas prices:
jan '07 : $us 2.78 to 3.83/mmbtu
feb '07 : 4.83 to 5.66
mar '07 : 4.74 to 5.23
apr '07 : 2.18 to 3.08
may '07 : 3.65 to 3.82
jun '07 : 2.62 to 2.79
jul '07 : 1.99 to 2.85
elwooddelmore:
I've a friend who got 3 coalbed methane wells dug i the Powder River Basin, and he had to sell his gas for $2/MCF just to keep his farm-in. He sold his wells, and has got a real job now.
Bob Ebersole
Bob,
Care to add anything more on the Powder and Tongue coalbed methane fields?
Development of these fields has cost both Montana and Wyoming. The dirty, saline waters trapped in the beds must be vented from these fields. There are major water quality issues, and they have lowered water tables throughout the region. Montana's governor filed suit this year, claiming Wyoming was stealing their water. IMO, it highlights a smaller version of the problems tar sands will produce, Here, the water problems don't have near the contamination of Alberta, but look at the mess.
doug fir, i dont have any firsthand knowledge of the water quality in the coal seams but i have heard that it is suitable for livestock( and pronghorn antelope). but if the water being discharged is of a low quality, then the water table on the low quality water is being lowered. so which way is it, is it bad water being discharged or is it good water being depleted ?
oilmanbob, I dont have a real job either but the royalties from coalbed methane are sweeeeeeeeeeeeeeeeeeeeet.
I do not have any firsthand knowledge either, relatives have spoken concern.
I do know the area is under a 10 year plus drought, so water is scarce irregardless. It creates alot of wiggle room for denial or "not responsible." The quality issue stems from untreated discharge, which is killing native vegetation along stream channels, creating saline creep, and killing fields among ranchers who have historically used these streams or rivers for irrigation. Existing surface water is usually of high quality, dumping all the overflow into it degrades it exponentially. The old saw-dilution is the solution to pollution-comes back to mind reversed.
There are several solutions, but only some operators are biting the bullet. I guess due to cost. First among these would would be re-injection or reverse osmosis. Unlined evaporation ponds are proving a boondoggle, from overflows and disposal of residue.
The companies and ranchers have been fighting in court for years. Enough said on that-allegations back and forth and only money is spent, little solution.
As to suitability for livestock and antelope, you can drink water, as I know from personal experience, that surface applied regularly kills. The evaporated salts are left on the surface and evaporation rates in the area are very high. Though I am not familiar with the Powder-Tongue area, I know in other areas water wells may be 500 ft deep, grabbing what we termed "geologic water" Compared to closer water or sweet springs, it's foul stuff. Add a softener, do what you have to.
I got on this board from a deep concern and worry about energy supplies. I like other views. I hate to throw out or belittle solutions. But we have to pay the cost, not find more externalities.
Generally it does not matter. The US for example went on a drilling campaign when it peaked in oil. You need continuous growth to keep even. Once you pull back you need say twice the previous growth rate to catch up.
This problem which is caused by increasing costs and manpower shortage. When your in a situation that requires exponential growth and you hold steady or slowdown your basically behind forever and will never catch up thus you have peaked. Its actually very impressive what the oil and gas industry has accomplished to date.
This above ground factor is probably the reason that oil production peaked earlier predicted and I suspect we will find that the same processes will lead to a earlier peak for North American NG and a steeper decline rate over whats been predicted.
So probably we will be hit with high gasoline prices summer 2008 and sporadic shortages followed by NG issues that winter. Considering the decline rates for NG I can't see how we won't have problems winter 2009.
It's not a question of bringing production back on line. Wells are not (in general) going off line until finished. It's a failure to drill more and more wells each year. Catching up again is not going to happen. The flat production over the last six years or so was achieved only by enormous and ever-increasing effort. Just continuing with enormous (and not increasing) effort will result in decline. Actually slacking off will result in faster decline.
The price is not low by historical standards. The problem is that the size of individual deposits of new gas keeps falling, so more and more holes had to be drilled each year to offset the decline in existing production. This cost more and more each year, and eventually (inevitably) it was just too expensive to keep up.
No conceivable effort will get production up again to where it was. As for bitumen extraction and upgrading, the interesting question will be how quickly things can be changed so that asphaltene fractions or coke are used for heat and to supply hydrogen.
PaulusS,
Its a combination of both lower prices and geological problems.
When the huge natural gas field under Ft. Worth and Dallas was figured out by George Mitchell and his company he had been trying to produce this gas for 30 years. He knew it was there because he always got a gas kick drilling through the Barnett Shale in Wise County, but no operator been to produce the gas at a profit. He worked out how to lower the cost of fracturing the wells, and purchased leases on a huge amount of acreage in the best part of the field for a reasonable figure. He then sold his company to Devon Energy for a lot of money and more or less retired-he's about 90 years old and has been very sucessful as a wildcatter since the 1940's.
As Devon's wells became profitable, dozens of other companies purchased leases in the Newark East field, and a trend play began on acreage that stretched from El Paso to upstate New York on similar plays.
Then, hurricanes Katrina and Rita hit, and the price for natural gas went from $7.00 or $8.00 per thousand cubic feet, or MCF to as high as $15 MCF. At the same time, the US economy was booming, and Hedge Funds eagerly committed themselves to big and expensive drilling programs, which assumed that natural gas prices would remain above $10/MCF and that drilling and completion prices would escalate by perhaps 50%, but still remain reasonable. They also assumed that there would be a good market for the gas, as the United States was past its peak in production.
At the same time many companies began to permit and build Liquified Natural Gas plants overseas and also in the United States. There are hundreds of trillions cubic meters of "stranded" natural gas deposits in the world, much of it produced along with oil in fields all over the world. Jerome a' Paris covered their location in his post on building natural gas pipelines in TOD-Europe archives about a month ago. In many countries, such as Nigeria, this gas is just wasted, or flared as there is no market. So companies who can sell it in the United States are getting money for something that would otherwise just be flared (burned). There have been around 20 LNG plants completed so far in the US, and more of them in the process of permitting or construction.
The result has been that all the gas storage facilities are full, and gas prices have hovered around $6/MCF and $8/MCF for the last two years, and most of the wells that were budgeted with an anticipated gas price of at least $10/MCF are not making a good profit. Another problem that has weighed down on investment in gas wells is that so many hedge funds are having a very hard time and they are experiencing a hard time getting financing, so the operators and and funds are selling futures contracts, which are depressing the price of natural gas.
The prices of drilling and completing natural gas wells in the field has gone up relentlessly, and now is double what was originally budgeted for by the operators. There are not enough pipelines, and the ones in place are full. A large high pressure gas line is not the kind of neighbor anyone wants, and it costs very substantial sums of money to purchase or condemn rights of way for the pipelines across the cities to the sales line. World Oil had an article a few months back and only 40% of the verticle wells in the Newark East Field and about 10% of the horizontal wells are actually projected to make a profit.
This is an example of how wrong things can go in a boom. Alberta wants to raise its royalty rates on the wells in the biumen sands because the net profits basis on which the old contracts were based don't look like theyare going to materialize. Petrobank Energy's THAI process seems to be very successful so far, but it cuts the water consumption to produce the wells to nothing, and the natural gas requirements to zero. If there is a carbon tax imposed on the strip mines by the Canadian Government or its trading partners, they will be very unlikely to be profitable, and so all production will cease that uses this method, yet there will be an incredible clean-up bill for the problems caused so far.
The other method which companies are using for production is steam-assisted gravity drainage, which will be superceded by THAI. So, the market for the water and much of the natural gas looks not so hot.
The big oil companies have been very involved with the syncrude/bitumen processes because they allow them to continue to use their old equipment and refineries to produce gasoline and petrochemicals. If that changes radicially then their whole business will morph to something that they don't understand. If peak oil and climate change cause a radical change in how the world operates, then many of their old assets will be only liabilities. That's why they have resisted any discussion of the future, fear and uncertainty.
The other reason is geological. Although there is no exploration risk, prices of production are very high and, I understand cost approximately $100K per barrel per day of level production just for the equipment, but not including any production costs, or the office overhead.. This compares with the going market price of $50K per barrel per day of production buying stripper wells in Texas. Because the tar sands are so isolated and the pipelines are full, the price of bitumen received by the producer is at a substantial discount to the price of crude oil received anywhere in Texas. And, I've heard the producers are dumping water in containment ponds, polluted with heavy metals, sulfur and already covers about 40 square miles at Ft. McMurray. This practice was made illegal in the mid 1960's in Texas, and will probably be an ongoing financial and litigation liability for the operators and their successor companies.
Bob Ebersole
Thanks for a very informative post.