American Oil and Gas Reporter - March 2017 - 69

SpecialReport: Gas Processing & Treating
structing and installing a new amine plant
involves an upfront time commitment (typically three-six months), while an H2S scavenger solution can be deployed rapidly.
And finally, each sour gas well must
go through a permitting process. In some
cases, such as permit by rule, the approval
process requires no more than submitting
the relevant paperwork. In other cases,
cases such as a Texas Commission on Environmental Quality standard air permit
or the U.S. Environmental Protection
Agency Title V permit involving the emission of larger quantities of H2S, the approval
process can take more time and require
additional ongoing reporting. In the sixwell Eagle Ford project, the treating services
contract company worked with the operator
throughout the permitting process.
Numerous contract treating providers
maintain fleets of both new and refurbished
treating equipment, which can be exactly
as efficient and provide a much quicker solution when considering project lead times.
In addition, leasing an amine plant
from a contract treating provider alleviates
the need for large upfront capital expenditures, and often includes turnkey services
such as installation, startup, commissioning
and ongoing operations and maintenance.
The bottom line is that the decision of
whether to select an amine plant or an
H2S scavenger must be made on a caseby-case basis and often is tailored to fit
the specific needs of the particular application. Contract treating companies can
provide the expertise and guidance in
helping operators make appropriate choices
to best fit their needs.
Multiwell Pad Case Study
Treating processes are used every
day to drive value for oil and gas com-

panies. In 2016, a producing company
was interested in the possibility of replacing an existing treating unit with a
refurbished plant for a multiwell pad.
The gas analysis determined that a more
appropriately sized amine plant would
provide savings in chemical and power
consumption, while lowering the monthly
lease costs.
The customer needed to flow five
wells through the amine plant. From the
start, the H2S concentration was 160 percent higher than expected. To offset the
higher H2S concentration, engineers from
the contract treating services provider
added DGA to the amine stream. The
chemical was added slowly, at the rate of
a few gallons a day, to ensure the gas
was not overtreated. After several weeks
of treating, monitoring and adjusting the
chemical blend, the plant treated below
the pipeline specification.
The improved efficiencies and reduced
costs associated with implementing an
appropriately sized amine plant are yet
another example of how improved processes are leading the way in the natural gas
treating sector.
The stabilization of commodity prices
in recent months has created a renewed
sense of optimism throughout the industry. Operators are beginning to put
capital back to work and production volumes appear to be poised to begin increasing again. And natural gas treating
solutions are continuing to play a significant role in their success. No one
can say for certain whether a new technology will revolutionize the gas treatment sector, much like horizontal drilling
did for the drilling industry, or whether
improved processes will remain the dominant form of advancement for treatment

companies. Regardless, one certainty
does remain: natural gas treatment solutions will continue to play an influential
role in America's drive toward safe, reliable oil and natural gas development.
❒

STEPHEN
MORGAN

Stephen Morgan is senior vice
president of Houston-based TransTex
Treating, which provides contract
treating and processing solutions to
operators and midstream companies.
He manages all aspects of the business
unit, including sales and commercial
development, strategic planning, engineering, and field operations. Morgan previously directed the company's
business development team, leading
to its acquisition by Eureka Midstream
in 2012. He serves on multiple boards,
including as president of the Young
Professionals in Energy (YPE-Houston), a nonprofit with 40 chapters
and approximately 40,000 members
worldwide that aims to facilitate the
advancement of young professionals
in the energy industry through social,
educational, and civic service opportunities. Morgan holds a B.B.A. in
management from Sam Houston State
University.

STACK Well Sets Continental Record
OKLAHOMA CITY-The Angus Trust
1-4-33XH well produced 4,642 barrels of
oil equivalent in a 24-hour test, comprised
of 2,088 barrels of oil and 15.3 million
cubic feet of natural gas, establishing a
company record for the overpressured oil
window of Oklahoma's STACK (Sooner
Trend Anadarko Canadian Kingfisher)
play, Continental Resources announces.
The well flowed at 5,200 psi during its
initial production test, Continental adds.
The company says the Angus Trust
well is located immediately north of its

Boden 1-15-10XH well in south-central
Blaine County, Ok. The Boden produced
an initial 24-hour test rate of 3,508 boe
(28 percent oil) at a flowing casing pressure
of more than 5,000 psi. Continental says
the Boden was its first completion in the
condensate window of the overpressured
STACK. After a year, the company notes,
the Boden had produced 591,000 boe (26
percent oil), and still was producing 1,815
boe/d (22 percent oil) at a flowing casing
pressure of 2,900 psi.
"The Angus Trust is another tremen-

dous STACK Meramec well," praises
Continental Chairman and Chief Executive
Officer Harold Hamm. "Aside from being
a company record well, it further validates
our perspective of the extent of the
STACK's overpressured oil window."
Continental estimates its total completed cost for the Angus Trust was $8.9
million, approximately 30 percent less
than the Boden. The Angus Trust's 9,500foot lateral was completed in 36 stages
with 20 million pounds of white sand,
similar to the Boden, it says.
❒
MARCH 2017 69

American Oil and Gas Reporter - March 2017

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