American Oil and Gas Reporter - February 2018 - 72

SpecialReport: Advancing Shale Science
practical purposes, the slickwater systems
that dominate the shale stimulation market
are environmentally friendly by nature,
with formulations containing up to 99 percent water by volume. The minimal amount
of chemicals used in slickwater frac fluids
generally consist of gelling agents for viscosity adjustment, surfactants to avoid
emulsification, inhibitors for clay control,
and chemical stabilizers.
However, it is important to keep in
mind that once a well is placed on line,
the composition of the water that flows
back to surface in the production stream
will be different from what was pumped
into the near-wellbore formation during
fracturing because it mixes with the in
situ reservoir water (brine). The mixing
of slickwater and resident water changes
the composition such that flowback
water essentially becomes a high-concentration saltwater. In addition, there
may be water influx into the reservoir
from nearby aquifers.
In horizontal shale plays, the best segments along a lateral for hydraulic fracturing are generally those sections with
high brittleness/low ductility (low clay
content). There is always some deformation that causes the induced fracturing of
a brittle formation. These induced fractures
can form the pathways for the migration
of water from nearby reservoirs to invade
the reservoir, in addition to the water
leaked off from fractures created during
well stimulation.
The fluids flowed back during production contain dissolved salts, residue
chemicals, sand and other solids that can
be removed to allow slickwater systems
to be recycled, which can reduce fracturing
fluid costs and minimize the overall volumes of water required in a completion
program. Recycling strategies are particularly well suited to multiwell pad operations, but recycling does introduce additional demands associated with on-site
treating and storage of recovered fluids.
The economics of handling field water
are influenced by several issues, but an
important bottom-line consideration is the
critical produced water-to-oil ratio (WOR).
It is defined in terms of the amount of produced hydrocarbons that is sufficient to
pay off the cost of produced water handling.
The equation required to calculate the
critical produced WOR is the profit acquired
from one barrel of oil equivalent compared
with the handling cost of one barrel of
water associated with various water handling
operations, including lifting, treatment, dis72 THE AMERICAN OIL & GAS REPORTER

posal and recycling. A positive critical
WOR results in positive cash flow, while a
negative critical WOR results in negative
cash flow.
Treatment Options
Among the factors that impact the
selection of the best treatment option for
a given field application are produced
water constituents, treatment space availability, recycling/reuse needs, disposal
options, byproduct generation, operating
period and cost-effectiveness. Salinity
and total dissolved solids are key in determining an effective treatment strategy.
The ideal solution is in situ treatment
using downhole separation and recycling,
avoiding bringing produced/flowback
water to surface, and thereby eliminating
surface handling, separation, storage,
measurement and transportation costs.
However, in situ treatment is operationally
and economically challenging in conventional reservoirs, and impractical in
ultralow-permeability shale formations.
In onshore operations, the basic treatment methods can be classified as physical,
chemical and biological. Treatment using
a single method often is not able to meet
all the desired standards, requiring a combination of one or more methods, which
impacts project capital and operating
costs. Typically, water treatment processes
consist of physico-chemical pretreatment
followed by biological treatment. Common
processes include halophile oil degrading
microorganisms, combined membrane
and biological treatment, combined membrane and ultrafiltration, anaerobic and
aerobic treatments, and immobilization
additives-aided biological treatment.
Each type of treatment has advantages
and disadvantages that must be considered.
For example, physical methods generally
have high initial cost and have difficulty
in accommodating variable water conditions. Chemical methods usually involve

high operating and maintenance costs,
and are challenged by changing water
concentrations and sludge production.
On the other hand, varying salt concentrations and types of organic species can
be problematic for biological methods.
There are any number of best practices
for optimizing water handling using conventional approaches based on efficient
and economically viable technologies.
The essential tasks of integrated water
management can be summarized as determining available water resources, reducing freshwater utilization and reusing
wastewater, determining water requirements, balancing water supply/demand,
allocating water sources to appropriate
cases, identifying the best treatment methods, and comparing the advantages/disadvantages for the best and most cost-effective compromises.
To optimize the water life cycle, oil
and gas companies need to understand
the mechanisms and patterns of water
flow to know where water is coming
from and where it is going by monitoring
wells, analyzing data and running reservoir
simulations. Well locations and drilling
patterns help define how water moves in
a field development, and commercial diagnostic and software tools are available
to help operators model and monitor conditions in the field over time.
Operators also need to identify production bottlenecks to optimize the overall
system from the reservoir to surface facilities,
and conduct accountability and balancing
studies to determine volumes produced,
treated, recycled, reinjected, etc. In many
cases, factors that may be regarded as secondary side issues in initial production
planning turn out to be very important in
designing the water management program
and the ability to enhance the performance
of tanks, pumps, treatment facilities and
other equipment. Operators will be wise
to adopt a hierarchical planning methodology that includes contingencies to meet

DENVER-U.S. Energy Corp. says its
Beeler Ranch No. 1H, a 26,000-foot total
measured depth dual lateral well in Zavala
County, Tx., averaged 1,046 barrels and
1.08 million cubic feet of natural gas
over the well's initial 24 hours on production.
According to the company, the Beeler
Ranch No. 1H had a flowing tube pressure
of 1,118 psi on a 22⁄64-inch choke. Cumulative production over the well's first
eight days totaled 7,200 barrels of oil

equivalent, with an 81 percent oil cut.
"We are extremely pleased with the
results from the Beeler Ranch No. 1H
well, the initial well in U.S. Energy's
drilling participation program," says company chairman and chief executive officer
David Veltri. "The success establishes
development potential on the company's
adjacent acreage position in Dimmit
County, where as many as four additional
wells may be drilled at an increased
working interest for U.S. Energy."
r

U.S. Energy Completes Zavala County, Tx., Well



American Oil and Gas Reporter - February 2018

Table of Contents for the Digital Edition of American Oil and Gas Reporter - February 2018

Contents
American Oil and Gas Reporter - February 2018 - 1
American Oil and Gas Reporter - February 2018 - 1
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