American Oil and Gas Reporter - June 2018 - 72

the wellbore architecture as lateral lengths
increased to 10,000 feet.
Figure 3A illustrates the third-generation design now in use for 10k laterals.
It includes a 171⁄2-inch hole with 133⁄8inch casing surface section. The 121⁄4inch intermediate section has 95⁄8-inch
casing set at the KOP of the curve interval.
The production section consists of an
81⁄2-inch hole and 51⁄2-inch casing. This
design successfully isolates the water
flow and lost circulation zones from
lateral reservoir pressures. The 81⁄2-inch
lateral hole allows the use of an RSS to
significantly improve drilling performance
by reducing friction and improving weight
transfer. The production casing design
does not compromise the ability to pump
at designed rates during stimulation.
The original well design is still used
in some areas, provided that water flows
are not present and lateral reservoir pressure is low enough to allow low mud
weights to be used (8.0-9.5 pounds/gallon).
This allows the lateral to be drilled while

not inducing losses in the Delaware formation. The original design has been upsized to have an 81⁄2-inch lateral hole size
(Figure 3B) to enable the use of an RSS.
This design is applicable to all three
lateral lengths (5K, 7.5K and 10K).
Typical Layout
Multibench development requires extensive planning to minimize collision
risks from wells in close proximity. Generally, each of the productive benches in
a well requires a separate wellbore. Figure
4 shows an example of the concentration
of wellbores in a typical layout. A section
with six benches and six wells per bench
would require a total of 36 wells, with
each surface location near the edge of
the section to place the lateral through
the maximum legal producing length.
Typical layouts of one-section and
two-section developments with approximate dimensions are shown in Figure 5.
The blue lines are wells. The outside
boundary is the section border, and the

FIGURE 5
Typical One-Section (Left) and Two-Section (Right) Developments
One Mile

Two Miles

10K Laterals

5K Laterals

One-Section Development

Two-Section Development

FIGURE 6
Two-Well Pad with Wellbore Uncertainty Ellipses
Around Previously Drilled Well (in Purple)

00

1,5

00

3,0

00

4,5

00

6,0

0

0
7,5

00

9,0

00

,5
10

00

,0

00

-3

,5

-1

0

0
,00
12
0
,50
13
0
,00
15

72 THE AMERICAN OIL & GAS REPORTER

dashed lines inside are the allowable producing areas. Two, three-well pads are
used in a typical single-bench development. Pads may be inside the section,
close to the boundary, and in some cases,
on the adjacent section surface.
Development plans are influenced by
both the effect on well paths close to adjacent wells and the need to deviate wells
to position the beginning of the lateral.
Nearly all wells are drilled both away
from the lateral ("back build") and perpendicular to the lateral path ("side build")
for well separation, then turned in the direction of the lateral. Wells are designed
so that the lateral will be in the target
formation at the start of the allowable
producing area. Total depth is past the
allowable producing area, allowing a toe
initiator to be deep enough that the first
hydraulic fracture interval will be at the
producing area border.
Long laterals and the need for directional path control between the surface
and the start of the horizontal creates well
path design complications, including:
* Anti-collision between adjacent
new wells and planned wells;
* Anti-collision between new wells
and existing conventional vertical wells;
* Well positioning precision;
* Survey accuracy; and
* Path designs for minimum friction.
Wells drilled from multiwell pads risk
collision with adjacent wells. Early in
the study period, wells commonly were
nudged a few degrees from vertical for
separation. The resulting doglegs and
side forces from these shallow nudges
proved to cause severe rod and tubing
wear on beam-pumped wells. The use of
RSS in the vertical section allows the
well path to be precisely controlled to
eliminate collision risk with minimum
doglegs (less than 1.0 degree/100 feet).
In older producing fields, there is collision
risk with existing producing, injecting and
abandoned wells, as depicted in Figure 6.
This makes it necessary to understand the
wellbore positions of past, current and
future wells. High-density gyro surveys
and multistation analysis significantly reduce
the risks with close-proximity operations.
Gyro surveys are run on existing wells if
possible. It is expensive to pull artificial lift
equipment, so generally a gyro is run when
wells are pulled for any reason.
Sometimes, wells are drilled from a
surface location on an adjacent section,
which can result in interference with crossing wells drilled from the other section.
Oxy's practice is to design well paths for
all wells in all potential benches to avoid
creating limitations for future wells.



American Oil and Gas Reporter - June 2018

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