American Oil and Gas Reporter - August 2017 - 66

SpecialReport: Horizontal Wellbore Construction
Some junctions have preferential fracturing and completion methods, such as
when an operator wishes to have cement
isolation at the junction but chooses to
install an open-hole frac sleeve or a
packer completion with ball-drop actuation. This would require the junction area
to be stage cemented (level 4), which
would add cost to the overall project because of the additional equipment and
operations necessary to stage cement.
The upside is a cemented isolated junction
(i.e., no exposed formation issues while
producing the well).
Production management also can introduce challenges for multilateral wells,
where production is commingled from
different formations or different parts of
the same formation. Do pressure regime
differences exist that require a higherlevel completion to properly manage
commingled production? Would any
issues be resolved by simply keeping
one lateral plugged while producing the
other to a certain decline rate before commingling both laterals? If the junction is
not isolated, the longer-term effects of
production have to be taken into account
since the formation will be exposed to
production flow.
Separation at the heel is another consideration. The spacing of laterals, build
rates and maximizing the length of the
lateral to the fracture will be impacted if
sufficient heel separation is not achieved
by the drilling program versus the kickoff
points and size of the section drilled.
Multilateral well architecture also is likely
to play a role in determining how artificial
lift is used to produce a well. Placing a
lift device to optimize production management may define the size and type of
lift device, as well as help define the preferred junction type and construction.
Major Consideration

The sequence of stimulation and completion operations is a major consideration
66 THE AMERICAN OIL & GAS REPORTER

in planning multilaterals. If the plan is to
drill, case, complete and frac all the
laterals back-to-back and reservoir pressures are sufficient, some type of mechanical barrier must be placed in the
lateral liner outside the main bore after
fracturing, flowing back and cleaning out
each lateral (at least for all secondary
laterals and likely as well for the main
borehole) to avoid having a live well
scenario. The question then arises as how
to retrieve or remove the barriers: drilling
rig, snubbing unit/hydraulic workover
unit, or a coiled tubing unit with suitable
risers/lubricators.
Re-entry may be another important
factor, especially if refracturing or
workover requirements are possible at
some later date. In a number of openhole level 1 junctions, operators have
utilized a bent sub motor or directional
motor to create a sidetracked lateral out
of an open-hole main borehole with no
means for re-entry. Most level 2 junctions
have been created by setting a bridge
plug at the kickoff point, followed by
setting a trip-activated whipstock to create
a sidetracked lateral out of a cased/cemented main bore. As with open-hole
level 1 junctions, accessing the laterals
requires indexing tools or bent subs since
there is no main bore positive re-entry
device.
An ideal solution for new wells is to
install a profile device, casing nipple or
coupling in the main bore to allow repetitive depth and directional positioning
for all drilling, completion, re-entry and
workover operations. A profile device is
an integral component to the casing/liner
in new wells where full casing internal
diameter is beneficial. For re-entry applications, a packer and orientation device
can be used to provide the same depth
and directional constant. However, the
packer will create a restricted access ID
to the lower wellbore should re-entry
into the main bore or lower laterals be

required (i.e., refracturing).
Managing surface facilities and operations between the drilling rig, workover
rig and/or CT rig, and frac spread requires
extensive preplanning. How these components are logistically planned and utilized impacts capital expenditures, and
therefore, requires careful consideration
when planning a multilateral well in an
unconventional play. Additional trips and
extra mobilization/demobilization costs
are likely with multilateral wells, especially
as junction level complexity increases.
These costs will be associated with both
drilling and completion.
Operational Sequence

The sequence of drilling and multistage
completion operations has varied from
project to project, but most have either:
* Drilled, completed and produced
one main bore lateral (until decline), and
then plugged it and repeated the process
for the secondary lateral; or
* Drilled both laterals, but completed
and produced only one lateral until decline,
and then plugged it to re-enter and complete and produce the secondary lateral.
In some cases, operators have used
artificial lift to produce each individual
lateral to a predetermined decline level,
lifting the first lateral and then plugging
and moving to the next lateral. After all
laterals have been individually produced
to the decline level, the plugs are often
removed and commingled production
from all laterals is artificially lifted to
surface. In very low-pressure formations,
artificial lift has been used to simultaneously produce multiple laterals from the
start of production.
As shown in Figure 1, stimulating a
multilateral requires either running a
packer-based junction isolation tool to
allow fracturing down the intermediate
casing string into the lateral completion
liner (isolating the junction from pressure
and isolating the laterals not being stim-



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