Swellpacker™ System Delivers Step Change in Zonal ... - Halliburton

E A S Y W E L L
Swellpacker Technology
Bests Zonal Isolation
Challenge in High-Pressure
Wells
R e d Te c h PA P E R
Part of the RedTech Learning Series
O c t o b e r 2 0 0 7
HALLIBURTON

E A S Y W E L L
Industry Challenge
The field to be developed contains several reservoirs that share the general features of being deep,
highly pressured and sour. Reservoir simulations for a major Middle Eastern Operator’s first EOR
project in southern Oman indicate a significant increase in recovery can be achieved, but only by
successfully isolating gas and water in the event that either or both breaks through prematurely to
producing wells from the miscible gas injection wells. To obtain the additional reserves, zonal
isolation is required, however, conventional cementing techniques have proven unsatisfactory.
Cement bond logs run in every well showed in practically every case that a microannulus
conductive to reservoir fluids had been created, preventing zonal isolation. Innovative cementing
techniques to increase the probability of reliable zonal isolation and minimize expensive workover
operations are required.
Halliburton Solution
Combining oil-swellable elastomer technology (Halliburton’s Swellpacker isolation system) with
a primary cementing job provides an effective means of addressing microannulus concerns and
incomplete cement sheath issues. This is a technically viable option to meet the EOR project’s
stringent zonal isolation requirements in the event the cement debonds from the casing and
hydrocarbons attempt to flow through the microannulus. Instead of the hydrocarbons conducting,
they instead activate the swellable elastomer upon contact; because the swelling rubber element
can conform to almost any irregular geometry, it can swell to close the microannulus and thus
reestablish the hydraulic seal required. To ensure an effective annular seal between multiple
reservoir layers, the Swellpacker isolation system can be installed as part of the production liner. It
can also act as a backup in the event that a microannulus is created at the cement/liner interface.
Operator Results
The Middle East field to be developed consists of nine reservoirs, each with distinct characteristics.
In general, the reservoirs are deep and highly pressured and they contain sour, light hydrocarbons.
More than 50 wells have been drilled in and around these fields. The initial wells have a shallow
13-3/8-in surface casing, a long 9-5/8-in production casing and a cemented 7-in liner over the
reservoir section. They are completed with 3½-in tubing and some have a permanent downhole
pressure gauge.
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The cluster is being developed in three phases. The objective
of Phase 1 was to determine from a number of data sources
whether a miscible gas injection project would be feasible in
some fields. Phase 2 will involve primary depletion in a
number of fields followed by gas injection in some of them.
Phase 3 will involve formation-wide depletion and gas
injection in the remaining fields. To maximize ultimate
recovery from these fields, gas (and water) shutoff is
required during Phase 2 and Phase 3 of the project.
Therefore zonal isolation over the reservoir is essential.
A substantial effort was made during Phase 1 to determine
whether zonal isolation was being achieved using
conventional cementing techniques. Cement bond logs were
run in every well over the liner section to determine the
quality of cement. These logs showed in practically every
case that a microannulus had been created. During well
completion, cement from the production liner debonded
because of differential pressure, leading to the creation of a
microannulus. Subsequently, the cement cannot re-seal and
a permanent flow path between cement and production
liner may arise, preventing zonal isolation.
Selective perforating during the well testing campaign
showed that this microannulus was conductive to reservoir
fluids. In one incident, reservoir fluids leaked all the way to
surface, providing further evidence of inadequate zonal
isolation.
Expandable pipe was not a technically feasible option owing
to the presence of high levels of hydrogen sulfide. A focused
effort was initiated to find an improvement over
conventional cementing techniques, and attention settled on
the Swellpacker isolation system.
Laboratory testing
To determine if the Swellpacker isolation system would be
able to withstand the anticipated differential pressure levels
in the various reservoirs, laboratory testing preceded a field
trial. Testing aimed to verify the cement assurance principle
of the Swellpacker isolation system with a 2-m-long, 4.82-in
outer diameter (OD) rubber element on a 4.5-in OD base
pipe placed in a 4-m-long, 6.1-in OD autoclave. The sealing
ability of the Swellpacker isolation system was tested by
introducing a microannulus on one side (90°) and allowing
the rubber element to swell and seal off the annulus by
flowing hydrocarbons through it.
The pressure test was aborted at 300 bar (maximum
pressure rating of the test unit) and the Swellpacker
isolation system was able to hold the differential pressure
with no detected leak. The system proved to be effective in
sealing off a simulated microannulus between the cement
and pipe interface and could withstand a differential
pressure in excess of 300 bar. The test also demonstrated
that the Swellpacker isolation system sealed off irregular
surfaces at the cement edge. These results provided
confidence that the Swellpacker isolation system can
effectively seal off a microannulus that develops downhole
between the pipe and cement interface—for example, as the
result of operations during well construction.
Field trial
It was therefore decided to run a field trial of the
combination of a cement slurry with the Swellpacker
isolation system. The objective of the production test was to
expose the Swellpacker isolation system to oil and then to
measure changes in flow rate, fluid composition and static
pressure. The critical parameters to be tested were as
follows:
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• ability to mechanically install Swellpacker systems
• ability of Swellpacker systems to withstand required
pressure differentials after expansion under production
conditions
• ability of Swellpacker systems to maintain zonal isolation.
The trial well was drilled in November 2005 as a vertical
production well on the western flank of the target
Schematic Showing Typical Response of Cement Bond
Logs in Phase 1 Wells
carbonate reservoir. The reservoir from which the trial well
was producing was considered a direct analog and was
operated under a pressure maintenance scheme with highpressure
gas injection on the crest of the structure. The
reservoir consists of three main units within a 50-m-thick
gross interval: an upper Unit 1 that is poorly developed and
possibly gassed out in this part of the field, a middle Unit 2
(3.0–4.5% porosity) that is generally tight and the lower
main producing Unit 3 (11.5% average porosity, 90%
hydrocarbon saturation).
It was decided to install 3-m-long Swellpacker isolation
system at the top and bottom of the poor-quality reservoir
section (Unit 2). An additional Swellpacker system was run
Schematic Showing Consequence of Poor Cementing
between this reservoir section and an underlying higherpressured
reservoir to isolate the two formations. The
intent was to selectively perforate 5 m of Unit 2.
The test procedure was set up to produce from the interval
between the upper two Swellpacker isolation systems with
maximum pressure drawdown and to evaluate the annular
isolation provided by the Swellpacker isolation systems
from either of the more productive upper or lower zones.
The main indicators were flow performance and fluid
composition. For example, if annulus flow from the more
Schematic of the Test Well Showing Swell Packer Locations in
Relation to Reservoir Units
productive zones was occurring, then an initial high flow
rate followed by a decline could indicate the Swellpacker
isolation systems were swelling and sealing the annulus.
Alternately, if the produced fluid composition changed with
time or was different between zones, then annular isolation
could be assumed.
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Swellpacker isolation systems were installed as an integral
part of the cemented liner completion; they were positioned
across Unit 2 at depths of 2911 m and 2919 m. Each
Swellpacker isolation system element is 3 m long, 5.5-in OD
(before swelling) and mounted on a 4½-in casing joint. The
openhole diameter in the reservoir section is 8-3/8 in.
Swellpacker isolation systems were positioned approximately
5 m from the expected main productive intervals in Unit 1
and Unit 3. A third Swellpacker isolation system, placed in
the completion near the bottom of the reservoir to provide
annular isolation from the higher-pressured and potentially
water-bearing, deeper reservoir, did not form part of the test
design.
The production liner with the Swellpacker isolation systems
was hung off in the 9-5/8-in casing and cemented. The liner
was rotated while cementing with no losses reported. The
cement bond log indicated good cement coverage across all
low-porosity zones and potentially poor coverage across
high-porosity sections in the main reservoir zone in Unit 3.
The cement bond log showed 4 m of good cement coverage
below the middle Swellpacker system to the top of the
expected productive zones in Unit 3 in addition to good
cement coverage above the upper Swellpacker isolation
system and across Unit 1.
The combination of Swellpacker isolation systems and
cement achieved zonal isolation in all three zones as
indicated by selective perforating, wireline logging and
production testing. This is the first time that zonal isolation
has been observed in these challenging, high-pressure and
sour wells.
Operator Benefits
After perforation, stimulation and cleanup, a stable flow rate
of 345 m3/d oil (150 m3/m3 gas/oil ratio) at 6000 kPa of
flowing tubing head pressure was achieved from the two
perforated intervals. A production profile log shows that the
majority of oil production is from the Unit 3 perforations
(96%) with only 14 m3/d (4%) from the Unit 2
perforations. Productivity from the Unit 3 zone was as
expected.
The following conclusions about zonal isolation success can
be drawn from these field tests:
• Production test results from Unit 2 perforations indicate
flow performance as expected for a Unit 2 formation.
• The production test indicates no communication with the
more productive Unit 3 zone, even under high drawdown
conditions.
• The low gas/oil ratio fluid composition from Unit 2
perforations indicates no communication with possible
high gas/oil ratio zones in Unit 1.
• The production tests show good annulus isolation
between Unit 2 and Unit 3 perforations.
In summary, zonal isolation is crucial to the future success
of the miscible gas injection project planned for the
reservoirs in the field to be produced. Previous attempts
using conventional cementing technology alone have so far
been unsuccessful. Based on results obtained from both
laboratory and field tests, the oil-swellable elastomer
technology of the Swellpacker isolation system in
combination with cement have demonstrated zonal
isolation for the first time in these challenging high-pressure
reservoirs. This discovery could enable a significant increase
in reserves from these fields.
Swellpacker Technology
The Swellpacker isolation system employs standard oilfield
tubulars with rubber layers chemically bonded along their
length. The rubber element swells upon exposure to
hydrocarbons to form an effective annular seal through a
process known as diffusion, which occurs as hydrocarbon
molecules are absorbed by the rubber molecules and cause
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them to stretch. The oil enters the rubber, which swells the
packer and ensures that it will remain swollen, unlike water
swelling systems which can shrink due to the effect of the
osmosis process being reversible. Mere trace amounts of
hydrocarbons are sufficient to initiate the thermodynamic
absorption process.
The wellbore fluid’s viscosity and temperature are key
variables in determining the time required for the
Swellpacker system to absorb hydrocarbon and ultimately to
set. Swelling of the packer is consistent along its length.
Although hydrocarbons will not degrade the rubber, they
will alter its mechanical properties, such as hardness and
tensile strength, depending on the rubber’s volume increase.
Swellpacker elements are chemically bonded to a tubing or
casing joint with element lengths tailored to accommodate
the desired differential pressure. Slip-on sleeve designs are
also available, normally in 12-in and 3-ft lengths, but for
low-pressure applications.
Thousands of Swellpacker systems have been run in
numerous wells worldwide for a variety of applications,
including zonal isolation across the reservoir as a substitute
for cement and providing backup should the liner
cementation prove unsuccessful.
This Halliburton white paper is a summary of SPE 100361
“PDO’s Proactive Approach to Solving a Zonal Isolation
Challenge in Harweel HP Wells Using Swell Packers” by M.S.
Laws, J.E. Fraser, and H.F. Soek, Petroleum Development
Oman, and N. Carter, Easywell (now with Sensornet Ltd.);
paper presented at the 2006 IADC/SPE Asia Pacific Drilling
Technology Conference and Exhibition, Bangkok, Thailand,
13–15 November.
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Biblio # 10/07
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