American Oil and Gas Reporter - February 2015 - 64

SpecialReport: Unconventional Resource Science
The frac sleeves contain an internal valve
that provides better protection from wellbore conditions and cement operations.
The drive chamber and ports are filled
with cement inhibitor to prevent any possible cement from setting up in the sleeve.
The sleeves will not open prematurely
unless there is a packer set inside the
sleeve, just below the ports, and differential
pressure can build across the sleeves.
Once the packer is set in the proper
place in the sleeve, a pressure differential
is created by applying pressure down the
annulus of coiled tubing and the inside
diameter of the casing. Once the differential pressure is created in the drive
chamber, the pins are sheared and the
sleeve is in the open position ready for
the first stage to be fractured (Figures
2A and 2B). Once the fracturing operations
are complete, the packer is unset by applying up-strain on the CT. The packer
can be moved then to the next sleeve and
the same operations are repeated for all
installed sleeves.
Bone Spring Application
The Bone Spring formation in the
Delaware Basin includes three Bone
Spring sands that are topped by the Avalon
Shale. The Bone Spring is stratigraphically
located between the Wolfcamp Shale and
shallower Delaware sands (Figure 3).
The Bone Spring shows moderate porosity
and low permeability.
The horizontal well in this case study
was drilled with a lateral section of 4,671
feet into the Third Bone Spring sandstone,
which has a porosity range of 7-18 percent
and permeability of 2 millidarcy or less.
The 29-stage fracturing operation was
completed in four days of daylight operations using CTFS technology.

FIGURE 2A
CT Frac Sleeve in Closed Position

FIGURE 2B
CT Frac Sleeve in Open Position

Shear pins

Drive Chamber

Valve in open position

Valve in closed position

All frac sleeves were torqued up,
drifted and pressure-tested in a controlled
manufacturing environment prior to shipping to location. After arriving on location,
the 4.6 foot-long frac sleeves were inspected by field engineers and deployed
into the well in conjunction with 51⁄2-inch
casing joints. The casing and sleeves then
were cemented in place.
A day before commencing fracturing
operations, coiled tubing arrived on site
and a clean-out run was performed using
CT in conjunction with a mill and motor
to clean out any excess cement. CT was
pulled out of the well and the CTFS
BHA was rigged up.
As a continuous pumping technique,
CTFS operations required only eight to
15 minutes between stages to set the
packer and open the frac sleeves with
CT, keeping NPT to a minimum and allowing all 29 frac stages to be completed
in 33.5 daylight hours. The average perstage pump time was 50 minutes. The
sequential treatment design for each stage
included pumping a prepad of treated
water, a prepad of 20-pound linear gel, a
pad of 20-pound cross-linked gel, and
sand-laden 20-pound cross-linked gel.

FIGURE 3
Formations in Northwestern Shelf, Delaware
And Central Platform Sub-Basins
Northwestern
Shelf
Glorieta
Upper Yeso
Yeso

Series

Leonardian

Permian

System

Middle Yeso
Tubb

Delaware
Basin
Avalon Sand
First Sand
Second Sand

Lower Yeso

WolfCampian

Central Basin
Platform
Upper Clearfork
M. Clearfork
Tubb
L. Clearfork

Third Sand
ABO

Wichita
Wolfcampian

Hueco

64 THE AMERICAN OIL & GAS REPORTER

Wolfcampian

Packer

Stimulation Operations
The prepad and pad fluids of each
stage were used as flush for the pervious
stage to reduce water usage. Proppant
concentration was "stair-stepped," starting
at 1.0 and incrementally increasing to
1.5, 2.0, 3.0 and 4.0 pounds per gallon
(psa). Clean fluids used per stage averaged
1,613 barrels, pumped at an average rate
of 40 bbl/minute with an average of
78,730 pounds of proppant pumped per
stage.
The first stage was pumped as designed
to completion. A slight change in treatment
design was implemented for the remaining
stages: The prepad of treated water was
taken off the pump schedule. Despite the
high surface treating pressure (STP) at
the beginning of stages five, six and nine,
the proppant substages were started as
designed without the apprehension of
screen-out since CT was already in the
well. The rate was reduced as STP approached the maximum pressure. Once
STP started decreasing, the pump rate
was increased to 40 bbl/minute, as designed.
Starting proppant pumping at high
STP would not be possible using plugand-perf techniques because of the lack
of contingency options in case of a screenout. It was not possible to initiate the
fracture for stage eight at first because of
high STP. The frac operation was paused,
and 15 percent hydrochloric acid (HCl)
was spotted directly at the ports using
the coiled tubing. The frac operation was
then resumed and the stage was pumped
to completion. Acid assisted in dissolving
cement at the sleeve ports to help initiate
the fracture. Therefore, acid was pumped
through coiled tubing and spotted at the
ports for all stages starting from stage 10
through the end of the job.
Fracturing stage 10 was challenging
because of sand left in wellbore from the
previous stage. However, with CT already
in the well, it was possible to circulate
American Oil and Gas Reporter - February 2015

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