Gee, it just reeks of Old Economy, and yet
folks these days are clamoring for it at whatever price the market
We're talking natural gas, the fuel-of-choice for
domestic electricity generation and staying warm during this frigid
winter. Storage supplies are dwindling, production levels are nothing
to write home about and prices have skyrocketed for this hot commodity.
So what could be more timely than the debut of a
new technique that could lead to an improved, safer and much lower-cost
way to pull additional natural gas out of marginally-producing fields?
A U.S. Department of Energy (DOE)-sponsored project
with RealTimeZone Inc. (RTZ) in New Mexico has successfully demonstrated
such a technique, which uses a new method of mixing the fluids used
to fracture, or frac, gas-bearing formations.
The natural gas industry spends more than $1 billion
per year to fracture these reservoir rocks to release more gas,
according to Gary Covatch at the DOE's National Energy Technology
Laboratory (NETL). The frac treatments allow increased reservoir
contact, with the fracture-creating fluids moving from the well
to as much as 1,000 feet or so into the formation to create channels
that let more gas move into the wellbore.
Traditionally, the fracture stimulation fluids are
mixed at the surface. RTZ, however, has developed a downhole-mixing
technique designed to give the operator more control over the fracturing
The company has applied the stimulation technique
in the Permian Basin, where it used the treatment to restore nearly
300,000 cubic feet/day (cfd) of natural gas production from a 12,300-foot
natural gas well scheduled for plugging.
The tab was half the price of a traditional frac
The precursor to the DOE-RTZ project dates back several
years when RTZ developed a real time stimulation diagnostic system
in conjunction with Halliburton, with some assistance from Schlumberger,
according to George Scott, one of the principals at RTZ.
Reservoir stimulation treatment monitoring has long
been practiced by completion engineers using radioactive tracers.
It was kind of an after-the-fact approach; however, where the gamma
ray tool was used after the treatment was pumped to detect tracers
behind pipe to discern where the treatment ended up, or the vertical
height of the treatment.
"The DOE was familiar with the patent we co-authored
with Halliburton for real time stimulation monitoring and contacted
us a little over two years ago," Scott said, "and they basically
wanted to fund continued development of the system."
All Mixed Up
DOE's National Energy Technology Laboratory (NETL)
is working with RTZ on the project, which is valued at $1.3 million
with the federal government contributing $922,000.
Scheduled for completion in June 2002, the effort
is in its last two phases:
- Field testing the downhole mixing technique.
- Real-time monitoring of the fracture as it is created.
"Once you observe a frac treatment in real time and
see what it's doing, you realize it would be nice to tweak a few
things here and there to modify and control the stimulation treatment
to maximize and optimize it," Scott explained.
For example, it's common to want to avoid excessive
fracture height while acquiring as much fracture length as possible.
Engineers also want to observe proppant placement occurring in the
"If you don't have a stimulation system to go hand-in-hand
with real-time monitoring," Scott said, "then what do you do with
"For instance, in the past when you're fracing a
well and the sand is concentrated too high, it'll pack off in the
fracture," he said, "and in a matter of seconds you'll have a screenout
and pressure that gets way high, way fast, and you must shut down
instantly or blow something up.
"If you tried to lower the concentration of sand
in the fluid at the surface it would be too late, because it would
take a half-hour to get it pumped and reach the perfs two miles
Enter downhole-mixing, where different components
are pumped -- some down tubing and some down casing -- that mix
down the wellbore.
When a pressure increase is detected, the completion
engineer can dilute the concentration of sand going into the formation
in real time by instantly increasing the tubing volume, likely avoiding
a premature screenout or early abort of the frac job.
Changes in stimulation pressures observed at the
surface allow the operator to know if the fracture is being created
as planned. Altering the fluid mixture can ensure the fracture goes
in its intended direction, and fracture length can be optimized
with minimized fracture height.
In other words, this real time system lets the operator
make adjustments "on the fly" to enhance the stimulation process
for greatly improved production results.
The Permian Basin, where RTZ plies its trade, is
fertile territory for implementation of the downhole-mixing system
Many producing zones occur with water zones in close
proximity, according to Scott, and a big frac job can easily treat
right into the water, causing irreversible damage.
In deep wells such as the Morrow, which is part of
the focus of the DOE-RTZ test project, the engineer is quite restricted
on what can be pumped as a function of pressure. So any method whereby
the operator can decrease the treating pressure is significant.
While real time stimulation diagnostic data typically
are most appreciated by the completion engineer, there's a lesson
here for reservoir geologists, according to Scott, who cautions
they need to be more cognizant of the entire completion process.
"The geologist might take the brunt of putting together
a bad prospect when, in fact, it was just stimulated out-of-zone,"
"It only takes about 30 minutes for a bad completion
to ruin a good well."
Scott noted the experimental Morrow frac job at 12,300
feet was accomplished at half the pressure of a typical frac treatment
-- 5,000 lbs/square inch versus about 10,000 -- and sported a price
tag of $40,000 versus $80,000 for a traditional fracture stimulation
"The zones we went into wouldn't have warranted a
substantial amount of money spent on a frac job," he said, "but
since we were able to do an experimental poor boy approach, we make
a commercial well with the technique.
"If we can go into wells about to be plugged or actual
dry holes -- which we plan to do -- and make any kind of production,
especially commercial production, it speaks volumes for how this
technology can be applied under even more significant circumstances."
The fluid used in the test was comprised of bauxite
mixed with a methanol gel at the surface that was blended with liquid
carbon dioxide (CO2) down the wellbore. The bauxite serves
as a proppant to keep the fracture open, and the gel and CO2
create the fracture, penetrating deep into the reservoir rock.
After the fracture is formed, the miscible CO2
becomes gaseous and moves out of the formation, allowing the fracture
fluid to be removed from the rock at a faster rate and enabling
the well to produce gas sooner.
If RTZ's technology can be used on even 20 percent
of the fracture stimulation treatments implemented by domestic gas
producers, it could save the industry more than $100 million per
year, according to Covatch at DOE-NETL.
He noted this could perhaps reduce natural gas prices
and allow companies to apply additional resources to locate and
produce more gas.