I do not believe personally that even the biggest of tight oil players can do what they say they can do without continuing to borrow enormous amounts of money. My question would be, what is, what will the total indebtedness of public, tight oil companies ultimately be and are they servicing that debt in such a manner that when they can no longer grow, or sustain production income streams will that debt be paid. Or will lending institutions that loaned the money be hung out to dry and need to be bailed out...by us? Far fetched? Maybe. Maybe not. CHK has been selling other tight oil assets to reduce their debt liability, what happens when those tight oil assets are actually plugging liabilities, production income is screaming down at the speed of sound and there are no more willing buyers? As we both know a dry hole, or a well that is depleted can't then be sold like a cow, or a duplex. When it's gone, brother its gone, right?
If the plan is to not drill so aggressively going forward that is contrary to the 40,000 well, 5 million BOPD, energy independence plan I hear ever day from fellas like Leo and I am a tad bit confused by that part of your statement.
They may believe in hyperbolic decline rates with long fat tails but that does not mean that's what they will get. The "reservoir" they drain is only as big as the frac radius they create. If we went on the hunt for fractured AC wells drilled in the 80's that produced 20 years we would be hunting a long time. We'd find a few that lasted 10 years, but not many. I am kind of a fan of Webble Telescopes work over at TOD; if these wells can produce at stripper well levels, which I doubt, the incremental lift costs per barrel are going to be astronomical. $50,000 dollar rod jobs don't work too well on 8 BOPD wells.
I think they have a fiduciary responsibility to their shareholders to keep a happy face. And to their lenders. And the prettier the picture they paint the more likely they are to be able to keep the little hamster wheel turning.
The shale revolution is “a little bit overhyped,” Shell CEO Peter Voser said last week as his company announced a $2.1 billion write-down, mostly owing to the poor performance of its fracking adventures in U.S. “liquids-rich shales.” Which of its shale properties have underperformed, Shell didn’t say, but CFO Simon Henry admitted that “the production curve is less positive than we originally expected.”
Shell was a latecomer to the tight oil game. As late as 2010 it was acquiring mineral rights at inflated prices, predicting that those properties would produce 250,000 barrels per day in five years. Three years down the road, they are yielding only 50,000 barrels per day, and the company intends to sell half of its shale gas and tight oil portfolio. Shell has officially abandoned its production target of 4 million barrels per day by 2012-2018. Instead, Voser said, “we are targeting financial performance.”
Second-quarter earnings were dismal for the so-called oil supermajors. Shell, BP, Exxon Mobil, Chevron, Total SA, Statoil, and Eni SpA all reported sharply lower profits.
Production was also down nearly across the board, with only Total SA reporting an increase.
Of course, none of this would be a surprise for those who read my article from March, “Oil majors are whistling past the graveyard.”
The declining profitability and production primarily owed to lower oil prices and rising costs. As Platts reported in June, total capital spending for the top 100 U.S. producers in 2012 rose 18 percent year on year. Costs will be higher still this year.
Rising costs are partly due to the tight oil boom itself. Producers that invested heavily in tight oil production are struggling to maintain output against the accumulating undertow of existing wells, where output declines rapidly. Geologist David Hughes finds an average decline rate of 60 percent to 70 percent for the first year of production in new wells in the Bakken shale of North Dakota. And a new statistical analysis by Rune Likvern at The Oil Drum shows production from most Bakken wells falls by 40 percent to 65 percent in the second year.
How do posters in this thread respond to this then?
Weaker refining margins and volumes associated with planned refinery turnaround and maintenance activities negatively impacted Downstream earnings.
The decrease was largely due to softer market conditions for crude oil and refined products. Earnings were also reduced as a result of repair and maintenance activities in our U.S. refineries.”
Oily Stuff wrote:...And lastly, if I may, let us not assume that drilling costs are going to go down, on average, in any tight oil play simply because Leo says they will. Where is the data to substantiate that?
...
EF wells, with average lateral lengths and average frac stages, at anything less than 7 million dollars. Maybe they can whack off a few days of rig time, and moving costs, by sliding a rig around on the same pad, big deal. A week of reaming and lost circulation, a stuck BHA and not so average well costs are above 8, easy.
Reger and other executives said drilling times also are dropping — to about 90 days from when the bit first hits the ground to initial oil and gas production. In early 2012, it took twice as much time because oil field services such as hydraulic fracturing teams were in short supply.
One well now can be drilled for $8.4 million to $8.8 million, and company officials see that dropping to $8 million on average by the end of the year. Some wells in Montana, because of the drilling circumstances, have cost under $5 million, the company said. Other wells, including some the company decided not to invest in, have cost $10 million or more.
The main reason for lower investment levels is improving costs. Hess can drill the average well in just 26 days compared to 32 days in the second quarter of 2012. That along with other costs savings measures has driven Bakken drilling & completion costs down from $13.4 million to $8.6 million over the past year.
During the quarter, the company released two traditional rigs and contracted a walking rig. SM plans to run three rigs through 2013. Almost all activity is infill drilling at this point. SM is has largely completed its exploration efforts and its efforts to hold leases with production.
Pad drilling has driven costs down 8% on the company’s Gooseneck acreage to an average of $6.5 million
TheServant wrote:DC,
First, thank you for responding to my earlier post. I figured 4000-9000 wells/yr in the Bakken was wildly optimistic, but thought I would throw it out there since it is apparently feasible (at least in TX) given data from the 2 TX tight oil plays.
This calls to question how long this kind of drilling can be maintained in the Texas plays. If I am eyeballing your first model on Eagle Ford, it looks like it has about 3000 cumulative wells drilled by mid 2013. If the previous article I linked is accurate and 4000 or so wells have been drilled in the past 4 quarters alone, it seems to be running well ahead of this first estimate. Perhaps active drilling in this play will wrap up before 2020 instead. Hard to say.
Still trying to envision where those rigs will go in several years once room for new wells begins to run out in the TX plays. I find your modeling interesting. Certainly a difficult task given all the variables involved. Thx.
Dave
ROCKMAN wrote:DC - Forget those numbers. Search engine screwed up. Double checked:
Last 12 months: 1439 oil. 249 NG
Last 6 months: 828 oil. 118 NG
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