American Oil and Gas Reporter - July 2018 - 56

SpecialReport: Horizontal Wellbore Construction
FIGURE 4A

FIGURE 4B

60
55
50
45
40
35
30
25
20
15
10
5
0

Target Parameter 'Sweet Spot' for 6¾-inch Curve
Sweet
Spot

0.09
0.08
0.07
0.06

MAX DIFF LIMIT

0.10
Standard Deviation of Tool face (deg)

Standard Deviation of Tool face (deg)

Standard Tool-Face Deviation Plotted Against WOB

DOC Target: 0.05

0.05
0.04
DOC Target: 0.03

0.03
0.02
0.01
0.00

0.00

5.00

10.00

15.00

20.00
25.00
WOB (klb)

DOC limiters designed to engage at a
targeted ROP. Figures 4A and 4B show
an analysis of the standard deviation of
tool-face and weight on bit (WOB) for
63⁄4-inch curves. The targeted parameter
"sweet spot" is located with respect to
DOC and motor differential pressure.
Long lateral sections require a durable
bit and BHA configuration for extended
run hours. A push-the-bit RSS system is
used with an aggressive 81⁄2-inch bit design
featuring six blades set with 16-millimeter
cutters and backup cutters on the shoulder,
and a 6.0-inch gauge length to prevent
damage. The best lateral performance using this RSS and bit combination is 9,751
feet in 59.5 hours (164 feet/hour). The
full length of the lateral remained within
the target zone.
Weight transfer is required for WOB
and running production casing to TD.
While drilling with an RSS, the drill string
can be rotated to avoid breaking static
friction when lowering the drill string.
With steerable motors, sliding friction becomes a greater limitation as lateral length
increases. Increased friction on longer
laterals (7,500-10,000 feet) makes it difficult to get WOB when sliding with a
steerable motor. The result is higher
average ROP in laterals with an RSS.
Running production casing requires
breaking static friction as each joint is
added. With rotation, casings can be
easily run to TD. On 5,000-foot laterals,
it is possible to rotate the casing without
exceeding the makeup torque of the casing
connections. On longer laterals, rotating
torque exceeds the rating of the casing
connections. Without rotation, repeated
pickup and slack-off cycles may be needed
to get the casing down the last few thousand feet.
Casing was run successfully to TD in
all 14 "10K laterals" (wells with 8,00056 THE AMERICAN OIL & GAS REPORTER

30.00

35.00

40.00

0.00

200.00

10,800 foot laterals) Oxy drilled in the
New Mexico Delaware Basin in 2017, although some required several hours to
work down the last 2,000 feet. The success
is attributed to oil-based mud, optimized
trajectories, low-friction centralizers and
close operational supervision. Older wells
with casing run in water-based mud required
lubricants to reduce wellbore friction.
Drilling Fluids And Cementing
The drilling fluid program was developed
in three distinct stages. Initially, saturated
and diluted sodium chloride (NaCl) brines
were used in both vertical and lateral sections. In the second stage, cut brines were
replaced with mixed-metal hydroxide
(MMH) water-based fluids for vertical sections and invert-oil emulsions for laterals.
In the third and current stage, fluids are
both direct and invert-oil emulsions to drill
the vertical and lateral sections.
The Delaware sands in Southeast New
Mexico have been developed since the
1950s, and water injection to enhance
production from these sands began in the
1990s. As a result, the now-depleted
Delaware sands are lost circulation hazards,
particularly the Brushy Canyon sands.
Water flow hazards are more common in
the Bell Canyon sands.
The majority of the early horizontal
wells had surface casing covering freshwater zones. A shallow intermediate "salt
string" casing covered the Salado (salt)
and Castile (anhydrite) formations, and
production casing covered the Delaware
Mountain Group (sand) and Bone Spring
formations (sand and carbonates). Saturated NaCl brine was used to prevent salt
washout while drilling the intermediate
section, and both freshwater and cut NaCl
brine fluids were used to drill the laterals.
However, significant nonproductive time
occurred with exposure to both higher

400.00 600.00 800.00 1,000.00 1,200.00 1,400.00
Differential Pressure (psi)

pressure water flow zones and depleted
reservoirs.
Well designs were changed in late
2015 to deepen the intermediate casing
to isolate depleted sands from the curve
and lateral sections as well as cover the
salt section. An MMH water-based system
was implemented successfully. The rheological properties of the MMH system
resulted in reduced salt section washouts
and reduced lost circulation. The disadvantage of MMH was the amount of dilution required to maintain density and
the resulting high fluid disposal costs.
In 2017, Oxy successfully implemented
a direct emulsion water-based system consisting of saturated NaCl brine as the
external phase and emulsified diesel as the
internal phase. The saturated brine phase
minimizes salt washout while the diesel
phase lowers density to minimize lost circulation, eliminating the need to dilute and
reducing disposal costs. Invert emulsion
OBMs are used to drill the curve and
lateral sections. Although the lateral reservoirs are stable enough for WBM, OBM
allows higher ROP by reducing friction,
thus reducing torque and drag-essential
for drilling and casing 10K laterals.
Two-stage cementing tools and annular
casing packers initially were used to set
cement on intermediate casing strings.
To reduce costs, primary cement jobs
were designed to circulate to surface,
with the stage tools and annular casing
packers used in contingency. But the lowdensity, high-compressive strength slurry
was expensive, and the success rate for
circulating cement to surface on the first
stage varied between 50 and 75 percent.
A cost analysis showed that a twostage job was less costly. The two-stage
design reduced the volume of high-compressive strength, low-density cement
by almost 50 percent, thereby reducing



American Oil and Gas Reporter - July 2018

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