We have been
at it for a decade and we still have not developed confidence in our production
modeling and by extension in our reserve calculations. Yet it was also clear from the outset that
this was going to be a problem but that did not stop blue-skying the
reserves. For that reason alone I have
been hesitant to join the shale party as an unreserved booster.
I really
suspect that we are actually swapping dollars in most situations and it has
been fueled by fresh money. Nothing
wrong with this except that one must then find a way to drive real drilling
costs much lower and that is presently impossible.
Swapping
dollars is a lousy way to meet our supply needs although it certainly produces
a huge number of well-paying jobs.
I wonder if
rotating spiraling radio waves would induce superior reservoir response? We really need something that cute here to
draw the oil out.
Old
math casts doubt on accuracy of oil reserve estimates
Posted on April 3, 2014 at 11:30
pm by Bloomberg
By Asjylyn Loder
Bloomberg News
Jan Arps is the most influential oilman
you’ve never heard of.
In 1945, Arps, then a 33-year-old petroleum
engineer for British-American Oil Producing Co., published a formula to predict
how much crude a well will produce and when it will run dry. The Arps method
has become one of the most widely used measures in the industry. Companies rely
on it to predict the profitability of drilling, secure loans and report
reserves to regulators. When Representative Ed Royce, a California Republican,
said at a March 26 hearing in Washington that the U.S. should start exporting
its oil to undermine Russian influence, his forecast of “increasing U.S. energy
production” can be traced back to Arps.
The problem is the Arps equation has been
twisted to apply to shale technology, which didn’t exist when Arps died in
1976. John Lee, a University of Houston engineering professor and an authority
on estimating reserves, said billions of barrels of untapped shale oil in the
U.S. are counted by companies relying on limited drilling history and tweaks to
Arps’s formula that exaggerate future production. That casts doubt on how close
the U.S. will get to energy independence, a goal that’s nearer than at any time
since 1985, according to data from the U.S. Energy Information Administration.
“Things could turn out more pessimistic than
people project,” said Lee. “The long-term production of some of those oil-rich
wells may be overstated.”
Calculate
reserves
Lee’s criticisms have opened a rift in the
industry about how to measure the stores of crude trapped within rock
formations thousands of feet below the earth’s surface. In a newsletter
published this year by Houston-based Ryder Scott Co., which helps drillers
calculate reserves, Lee called for an industry conference to address what he
said are inconsistent approaches. The Arps method is particularly open to
abuse, he said.
U.S. oil production has increased 40 percent
since the end of 2011 as drillers target layers of oil-bearing rock such as the
Bakken shale in North Dakota, the Eagle Ford in Texas, and the Mississippi Lime
in Kansas and Oklahoma, according to the EIA. The U.S. is on track to become
the world’s largest oil producer by next year, according to the Paris-based
International Energy Agency. A report from London-based consultants Wood
Mackenzie said that by 2020 the Bakken’s output alone will be 1.7 million
barrels a day, from 1.1 million now.
U.S. crude benchmark West Texas Intermediate
fell 41 cents to $99.21 a barrel at 10:10 a.m London time in electronic trading
on the New York Mercantile Exchange. It has risen 0.8 percent this year.
Inherently
uncertain
Predicting the future is an inherently
uncertain business, and Arps’s method works as well as any other, said Scott
Wilson, a senior vice president in Ryder Scott’s Denver office.
“No one method does it right every time,”
Wilson said. “Arps is just a tool. If you blame Arps because a forecast turns
out to be wrong, that’s like blaming the gun for shooting somebody. As far as
Arps being old, the wheel was invented a long time ago too but it still comes
in handy.”
Rising reserve estimates gives the U.S. a false
sense of security, said Tad Patzek, chairman of the Department of Petroleum and
Geosystems Engineering at the University of Texas at Austin.
“We have deceived ourselves into thinking
that since we have an infinite resource, we don’t need to worry,” Patzek said.
“We are stumbling like blind people into a future which is not as pretty as we
think.”
The Arps formula is only as good as the
assumptions a company puts into it, Patzek said. Estimates can be inflated when
Arps is based on limited drilling history for data or on a few high-performing
wells to predict performance across a wide swath of acreage. Forecasts can also
be skewed higher by assuming slower production declines than Arps observed.
Reserves
cut
In November 2012, SandRidge Energy Inc. (SD)
cut its reserve predictions to the equivalent of 422,000 barrels per well from
456,000. Five months later, the estimate was cut again, to 369,000 barrels,
company records show. Oklahoma City-based SandRidge has since made an
adjustment upward to 380,000 barrels per well.
The early, more optimistic forecasts were
based on a small number of high-performing wells, which led the company to
overestimate performance for its other acreage, said Duane Grubert, SandRidge’s
executive vice president for investor relations and strategy. The company now
has more than 1,100 wells and has improved its drilling. It is confident that
current estimates are reliable, Grubert said.
“Nobody knew that until we actually
ground-truthed the field by drilling it,” Grubert said. “What we came up was,
hmm, that initial estimate was a little high.”
Future
production
SM Energy Co. (SM), a Denver-based producer,
suffered a similar setback this year when its wells in the Eagle Ford shale in
Texas fell short of forecasts. The company on Feb. 18 cut its prediction in one
area to the equivalent of 475,000 barrels per well from 602,000. Estimating
future production from early data is a challenge for the industry, said Brent
Collins, a spokesman for SM Energy.
“This is especially true when you are trying
to estimate an average from a limited number of wells,” Collins said.
Both SandRidge and SM Energy use variations
of the Arps method, company records show.
Tapping shale formations differs from the
drilling in Arps’ day, said Dean Rietz, an executive vice president in charge
of reservoir simulation at Ryder Scott. The first commercial shale well was
drilled in 2004, 59 years after Arps published his method.
Gas
pockets
In 1945, oil production meant drilling
straight down to hit pockets of oil and gas that had become trapped after
migrating upward from deep layers of rock. Today’s drilling targets those deep
layers, boring through thousands of feet of the earth’s crust, then turning
sideways to chew for a mile or more through layers that are harder and less
porous than a granite countertop. The rock is shattered by a high-pressure
jet of water, sand, and chemicals to create a network of small cracks to allow
the oil and gas to escape. The largest fissures are narrower than the width of
a paper clip. The smallest are thousands of times thinner than a human hair.
On a graph, these fractured wells appear
to follow a different trajectory of decline than the conventional wells Arps
studied, said Lee.
To replace the Arps calculation, researchers
are testing new formulas with names worthy of indie bands: Stretched
Exponential, which Lee helped develop; the Duong Method, devised by Anh Duong,
principal reservoir engineer for ConocoPhillips; and Simple Scaling Theory,
which the University of Texas’s Patzek worked on.
Rietz has made a well simulation model to
predict production.
“Come back to me in 10 years, and I’ll tell
you how reliable it was,” he said.
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