American Oil and Gas Reporter - February 2015 - 145

Wastewater disposal injections usually
last years or decades-not days-giving
the fluids time to migrate away from the
injection point, he observes. While geothermal facilities often see direct impacts
from adjusting their injections, wastewater
injection operators have much less control
over future outcomes, McGarr says. However, he reports wastewater companies in
Oklahoma have seen some successes in
controlling their high-rate injections under
such traffic light restrictions.
Geothermal Seismicity
Under the traffic light system, operators
project the magnitude of the largest
seismic event expected, based on injection
levels, Majer explains. He cites as one
approach, a calculation developed by McGarr that estimates the amount of seismicity relative to the injected volume.
"If a certain amount of fluid is injected,
we should expect to get X amount of
seismicity, if all the volume change is
accommodated by seismic energy released.
It has been proven to be a pretty good
empirical relation," Majer offers.
The injection well's location plays a
large part in setting those thresholds,
Majer says. Sites in isolated locations
with few adjacent structures can cope
with higher-magnitude events than wells
in more-developed areas. He adds that a
key component of establishing those
thresholds is meeting the public's expectations. Land management agencies, including the U.S. Bureau of Land Management and Forest Service, want a simple
formula that allows them to set those parameters, Majer says.
Majer is the lead author for Protocol
for Addressing Induced Seismicity Associated with Enhanced Geothermal Systems,
a 2012 study sponsored by the Department
of Energy. Among the steps it recommends
for geothermal operators dealing with
regulatory and public concerns about induced seismicity are:
* Implementing an outreach and communications program;
* Selecting criteria for ground noise
and vibration;
* Establishing a seismic monitoring
system; and
* Developing a risk-based mitigation
plan.
Disposal well operators could take a
range of measures to reduce risks, the
study proposes, including modifying injection rates and stopping injection in the
worst-case scenario. The analysis warns
that it is better to gradually decrease wellbore pressures rather than immediately
shutting in the well, pointing to a pair of
geothermal projects that experienced magnitude 3.0-plus events after injections

stopped.
The protocol imposes a calibrated control process, dubbed the traffic light
system, as one method for directly mitigating seismic events. It also uses realtime monitoring and management of induced seismic vibrations to continuously
calculate ground motion as a function of
injection rates and time, the study says.
To help guide well management decisions,
it offers three boundaries:
* Red is the level of ground shaking
at which damage to buildings in the area
is expected to set in. Pumping is suspended
immediately.
* Amber is ground-motion levels high
enough for people to notice, but too low
to cause surface damage. Pumping proceeds with caution, possibly at reduced
flow rates, and monitoring is intensified.
* Green is ground motion levels either
below the threshold of general detectability,
or at higher levels, but at occurrence rates
less than the established background activity level in the area. Pumping operations
proceed as planned.
"A stop light system is not used in
isolation. You really have to know something about the area, including the potential
for property damage and what the likelihood is of that damage happening," Majer
says. "At that point, you set thresholds.
If you want to be very, very conservative,
you set the thresholds such that for any
felt earthquake you stop and re-evaluate
your injection rate and what you are injecting. Then, you start again."
Seismic Monitoring
Improving the quality of seismic monitoring is a hot topic in the geophysical
sector, Majer says. Scientists and researchers
have been working on new technology
and techniques for decades, but he says
because of induced seismic concerns, the
field suddenly is getting higher visibility.
"What needs to be done is to develop
better borehole instrumentation, and understand the fundamentals of why seismicity
is happening at some points and not others,"
he says. "These events don't happen with
the vast majority of fluid injections. The
pressures cannot build in these very permeable areas; you put fluid into the ground
and it flows away. But, if you are putting
it into tight basement rock, there is more
of a chance you will see an event."
The instrumentation for monitoring
wastewater injections is relatively inexpensive at roughly $10,000 for a package,
but Majer points out that drilling a 500foot well to place the seismic monitoring
equipment can run more than $50,000.
In lieu of subsurface detection, he
says six surface stations are the minimum
number needed to monitor an injection

site, with combined coverage totaling as
much as 50 square miles.
"In all the geothermal cases, they have
eight stations covering 10 square miles
around the injection points. But the geothermal industry uses that seismicity to
manage the reservoir, not just for hazard
assessments," Majer says. "The geothermal
industry gets the most bang for the buck
out of this seismic data because they tell
operators where the fractures and fluid
are going. They are mining heat with this
fluid, whereas the wastewater disposal industry is just trying to get rid of the fluid."
In order to calm public fears about induced seismicity and wastewater disposal
wells, the oil and gas industry must
support a public education campaign,
Majer suggests.
"The more you educate people, the
better it is. You have to tell them what
we know and what we don't know, and
why we think the risks will be low," he
says. "The geothermal industry has caught
on to that. It has been very good at educating the public and responding by readjusting its injection schemes if people
start getting upset about feeling too many
earthquakes. Protocols for best practices
in the geothermal industry are beginning
to move to the oil and gas industry." Ì

Wentworth's Tembo Well
Extends Data On Rovuma
CALGARY-Wentworth Resources
says drilling operations at the Tembo-1
well in Mozambique's Rovuma onshore
concession have been completed, and
natural gas has been found in Cretaceousaged sands. Anadarko Petroleum operates
the well, which was drilled to 14,937
feet true vertical depth.
According to Wentworth, petrophysical
analysis of the Cretaceous section indicates
36 feet of natural gas net pay. Natural
gas and some condensate recovered by
modular formation dynamics testing confirmed the petrophysical analysis. The
company says the well owners are assessing all the data recovered to determine
its potential commerciality.
The Tembo-1 well has been plugged
and abandoned, and the drilling rig moved
to the Kifaru-1 well location, Wentworth
says, adding the new well will target
Miocene sands and Msimbati gas fields,
as well and Eocene and Cretaceous sands.
"The Tembo-1 was an exciting well
and has provided additional information
about the Rovuma Basin. We look forward
to our continued exploration in the onshore
Rovuma block with the spudding of the
Kifaru-1 well," says Bob McBean, Wentworth's executive chairman.
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FEBRUARY 2015 145

American Oil and Gas Reporter - February 2015

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