American Oil and Gas Reporter - August 2019 - 96

SpecialReport: Hydraulic Fracturing Technology
perforations in the production casing.
Good diversion was achieved after the
second diverter pill was pumped, and the
well could be circulated down the tubing
and up the annulus at a rate of five barrels
a minute. A pulling unit cleaned out the
lateral to plug-back total depth (PBTD).
A 43⁄4-inch skirted bit was run on 27⁄8-inch
pipe for the lateral clean-out. A 9.0
pound/gallon brine was circulated at
PBTD with full returns.
The tapered casing string was run
inside the existing production casing without any running issues. While running in
the hole and circulating prior to the
cement job, the well was not circulating
consistently with full returns. There were
concerns that the diverter may have been
wearing off and perforations were opening
back up. With the tapered string on
bottom, the decision was made to proceed
with the cement job and pump lost circulation material ahead of the spacer in an
attempt to stem the losses. The lost circulation material was pumped, followed
by an 11-lbm/gal spacer and an engineered
13.2-lbm/gal tail cement slurry. The
cement was displaced with 9.0-lbm/gal
brine. No returns were observed until the
very end of the cement job.
A coiled tubing unit cleaned out debris
left inside the tapered string after the cement job, then jet-perforated holes close
to PBTD to enable pumping down guns
and a bridge plug for stimulating stage 1.
A frac crew was mobilized to pump a
22-stage modern frac treatment inside
the cemented liner using the plug-and-

perf technique.
While pumping stage 13, pressure communication was observed in the 41⁄2- by
51⁄2-inch annulus. The frac design was modified to pump 15-lbm/gal linear gel throughout the stage to aid in keeping treatment
pressures below 5,000 psi while pressure
communication continued to be observed.
Radioactive tracers were run during the
frac job on all stages. Post-frac tracer logs
showed poor zonal isolation with different
tracers detected all over the lateral.
Because of concerns about the ability
to circulate without losses in older and
depleted refrac candidates, subpar cement
jobs resulting in poor zonal isolation,
and the unreliability of liquid diverters
to seal off perforations, mechanical isolation techniques were pursued. Expandable liner technology was considered a
more reliable and effective method for
pressure and zonal isolation.
Expandable Liner Wells
An expandable solid tubular system
(System A) was selected to mechanically
seal off old perforations to allow a modern
eight-stage frac treatment to be pumped
in Candidate No. 2, which has a 1,600foot long lateral in the Upper Bone Spring.
The plan was to clean out the lateral, run
the expandable liner with top and bottom
anchor joints, install isolation joints with
elastomer seals, and then expand the liner
against the existing production casing to
seal off the perforations.
The artificial lift system in the well
was retrieved, and a retrievable bridge

FIGURE 1
Candidate 3 Well Tracer Log

96 THE AMERICAN OIL & GAS REPORTER

plug was set at the planned top of the expandable liner to isolate and allow testing
the integrity of the existing 51⁄2-inch casing.
A good test was obtained, which ensured
casing integrity and the ability to hold
pressure during frac operations. When
the well initially had been drilled and
completed, a 5,000-psi wellhead system
had been installed. This required the use
of a wellhead isolation tool to test the
casing to the 6,200-psi maximum pressure
anticipated during the frac treatment,
which was 80 percent of the casing's
burst rating.
Since the well could not hold a column
of freshwater after extensive depletion,
the lateral was cleaned out using a venturi-type system with a tapered mill on
bottom. Multiple clean-out runs were required to remove debris. A multiarm
caliper log was run on a tractor system to
check the internal diameter of the original
casing to ensure the expandable liner
could be run to depth and expanded.
The expandable liner was conveyed to
depth using an inner string. The system
utilized a cone that hydraulically expanded
a set of elastomer seals to anchor the liner
on the bottom. After slow progress initially,
a lubricant was pumped down the string
to reduce friction during the expansion
process. This helped reduce the overpull
requirements and made the process much
faster. Then, the rest of the casing was expanded mechanically by pulling up the
inner string to move the cone up hole.
The liner space out was designed to
place isolation joints with elastomer seals
in between each of the new perf stages,
isolating them from one another and covering each of the existing perf stages in the
original casing. At the top joint of the expandable liner, two anchor seals were hydraulically expanded to anchor the top of
the expandable liner to the original casing.
The System A expandable liner was
open-ended. To ensure that it could be
pressure tested, a bridge plug was set at
the end of the expanded liner. A wellhead
isolation tool was rigged up, and an attempt was made to pressure test the
entire system, including the original
casing in the vertical portion of the well
and the expanded liner in the curve and
lateral. The system was pressured to
6,200 psi, but the pressure slowly bled
off, indicating a leak.
The vertical portion of the original
casing and the liner top were isolated individually, and the leak was determined
to be in the expanded liner portion of the
lateral. With the frac crew standing by,



American Oil and Gas Reporter - August 2019

Table of Contents for the Digital Edition of American Oil and Gas Reporter - August 2019

Contents
American Oil and Gas Reporter - August 2019 - Intro
American Oil and Gas Reporter - August 2019 - 1
American Oil and Gas Reporter - August 2019 - 2
American Oil and Gas Reporter - August 2019 - Contents
American Oil and Gas Reporter - August 2019 - 4
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