Inflow Control Devices—Raising Profiles
Tor Ellis
Marathon Petroleum Company (Norway) LLC
Stavanger, Norway
Alpay Erkal
Houston, Texas, USA
Maximizing reserves recovery using horizontal wells requires management
of fluid flow through the reservoir. One increasingly popular approach is to use
inflow control devices that slow water and gas encroachment and reduce the
amount of bypassed reserves.
Gordon Goh
Kuala Lumpur, Malaysia
Timo Jokela
Svein Kvernstuen
Edmund Leung
Terje Moen
Francisco Porturas
Torger Skillingstad
Paul B. Vorkinn
Stavanger, Norway
Anne Gerd Raffn
Abingdon, England
Heel
Toe
Oilfield Review Winter 2009/2010: 21, no. 4.
Copyright © 2010 Schlumberger.
For help in preparation of this article, thanks to Ewen Connell,
Rosharon, Texas; and Mary Jo Caliandro, Sugar Land, Texas.
ECLIPSE, PeriScope, Petrel, ResFlow and ResInject are
marks of Schlumberger.
1. Al-Khelaiwi FT, Birchenko VM, Konopczynski MR and
Davies DR: “Advanced Wells: A Comprehensive
Approach to the Selection Between Passive and Active
Inflow Control Completions,” paper IPTC 12145,
presented at the International Petroleum Technology
Conference, Kuala Lumpur, December 3–5, 2008.
2. Raffn AG, Zeybek M, Moen T, Lauritzen JE, Sunbul AH,
Hembling DE and Majdpour A: “Case Histories of
Improved Horizontal Well Cleanup and Sweep Efficiency
with Nozzle-Based Inflow Control Devices in Sandstone
and Carbonate Reservoirs,” paper OTC 19172, presented
at the Offshore Technology Conference, Houston,
May 5–8, 2008.
3. Wellhead penetrations are holes in the wellhead through
which power cables and hydraulic lines must pass to
reach a device downhole. The number that can be drilled
is limited by surface area and by the amount of material
that can be removed from the wellhead without
compromising its integrity.
4. Jokela T: “Significance of Inflow Control Device (ICD)
Technology in Horizontal Sand Screen Completions,”
Bachelor thesis, Det Teknisk-Naturvitenskapelige
Fakultet, Stavanger, May 30, 2008.
> Heel-toe effect. Pressure losses along a horizontal wellbore in a homogeneous formation cause the
flowing tubing pressure to be lower at the well’s heel than at the toe. In time, and long before oil (green) from
sections near the toe arrives at the wellbore, water (blue) or gas (red) is drawn to the heel (top), resulting
in an early end to the well’s productive life. Inflow control devices inside sand screen assemblies equalize
the pressure drop along the entire length of the wellbore, promoting uniform flow of oil and gas through the
formation (bottom) so that the arrivals of water and gas are delayed and simultaneous.
30
Oilfield Review
Extended-reach and multilateral horizontal drilling techniques significantly increase wellbore/
reservoir contact. This augmented contact allows
operators to use less drawdown pressure to achieve
production rates equal to those of conventional
vertical or deviated wells. The ability to optimize
results from these standard configurations through
better reservoir fluids management has been
greatly enhanced by the development of remotely
operated inflow control valves and chokes. These
devices enable engineers to adjust flow from individual zones that are over- or underpressured or
from those producing water or gas that may be detrimental to overall well productivity.
Long sections drilled horizontally through a
single reservoir, however, present a different set
of challenges. In homogeneous formations, significant pressure drops occur within the openhole interval as fluids flow from TD toward the
heel of the well. The result may be significantly
higher drawdown pressures at the heel than at
the toe. Known as the heel-toe effect, this differential causes unequal inflow along the well path
and leads to water or gas coning at the heel
(previous page). A possible consequence of this
condition is an early end to the well’s productive
life and substantial reserves left unrecovered in
the lower section of the well.
Water or gas breakthrough anywhere along the
length of the wellbore can also result from reservoir heterogeneity or from differences in distances
between the wellbore and fluid contacts. Pressure
variations within the reservoir caused by reservoir
compartmentalization or by interference from
production- and injection-well flow can also
lead to early breakthrough.1 Carbonate reservoirs,
because they tend to have a high degree of fracturing and permeability variation, are especially vulnerable to uneven inflow profiles and accelerated
water and gas breakthroughs.2
Many completions designed for long-reach
wells include sand control systems. If these completions do not have isolation devices such as
packers, annular flow can lead to severe erosion
and plugging of sand screens. In the past such
annular flow effects were countered with gravel
packs or expandable sand screens. But gravel
packs often reduce near-wellbore productivity.
Expandable sand screens require complex installation procedures and are prone to collapse later
in the well’s life.
In traditional completions the solution to an
increase in water or gas cut is to reduce the
choke setting at the wellhead. This lowers drawdown pressure, resulting in lower production
Winter 2009/2010
Nozzle-Type ICD
Helical-Channel ICD
> Leading ICD types. Fluid from the formation (red arrows) flows through multiple
screen layers mounted on an inner jacket, and along the annulus between the
solid basepipe and the screens. It then enters the production tubing through
a restriction in the case of nozzle- and orifice-based tools (top), or through a
tortuous pathway in the case of helical- and tube-based devices (bottom).
rates but higher cumulative oil recovery. However, ated wells and in several types of reservoirs.4
this simple solution generally does not work in These devices are usually part of openhole comwells drilled at high angles.
pletions that also include sand screens. In addiIn wells completed with “intelligent” technol- tion, ICD completions often use packers to
ogy, operators may shut off or reduce flow from segment the wellbore at points of large permeaoffending zones using remotely actuated down- bility contrast. This strategy combats water conhole valves. But horizontal wells designed to opti- ing or gas cresting through fractured zones, halts
mize reservoir exposure are often poor candidates annular flow between compartments and allows
for such strategies. Extremely long wells often for isolation of potential wet zones.
have many zones. The limit on the number of
ICDs are also effective in reservoirs where
wellhead penetrations available may render it their ability to regulate inflow rates creates a sufimpossible to deploy enough downhole control ficient pressure drop at the toe of the wellbore
valves to be effective.3 Additionally, such comple- for the reservoir fluid to flow or lift filtercake and
tions are expensive, complex and fraught with other solids to the surface.
This article describes various ICD designs
risk when installed in long, high-angle sections.
As a consequence, operators often choose to and how they are modeled to suit particular
produce these multiple-zone wells using isolating applications. Case histories from Asia, the North
devices such as swellable packers. To mitigate Sea and the Middle East illustrate how these pasOSWIN09/10—Rick, story #2—Figure 03
crossflow and to promote uniform flow through the sive devices enable operators to increase well life
reservoir, they have turned to passive inflow control and ultimate recovery.
devices (ICDs) in combination with swellable packers. By restraining, or normalizing, flow through Velocity Control
high-rate sections, ICDs create higher drawdown Inflow control devices are included in the hardpressures and thus higher flow rates along the bore- ware placed at the formation/borehole interface.
hole sections that are more resistant to flow. This They use a variety of flow-through configurations
corrects uneven flow caused by the heel-toe effect including nozzles, tubes and labyrinth helical
channels (above). These devices are intended to
and heterogeneous permeability.
Whether intended for injection or production, balance the well’s inflow profile and minimize
ICDs have applications in horizontal and devi- annular flow at the cost of a limited, additional
31
Production rate per length, bbl/d/ft
12
10
8
6
4
2
0
Heel
Measured depth
Toe
> Reducing the influence of high-flow-rate areas. In a heterogeneous model ICDs reduced the fluid
inflow rate (blue) at the heel (within orange circle) to half that predicted for a screen-only completion
(red). However, they increased the inflow rate from the lower two-thirds of the well (within green oval)
including the toe.
Helical devices force the fluid to flow through
pressure drop between formation and wellbore
(above).5 They accomplish this by changing the channels that have a preset diameter and length.
flow regime from the Darcy radial flow within the The differential pressure provided by these
reservoir to a pressure-drop flow within the ICD. devices is determined by friction against the
Each of the basic types of ICD uses a different channel surface and is a function of the flow rate
and fluid properties.6
operating principle to achieve this backpressure.
The pressure drop within a nozzle-type ICD is
This viscosity sensitivity may result in ineffia function of flow rate as the fluid passes through ciencies, however, when backpressure at breakrestricting ports inserted into the basepipe or through streaks is not significantly greater than
into the housing outside the basepipe. As that in areas producing oil that has lower viscosBernoulli’s principle states, the pressure drop ity because of entrained water and gas.
through a port increases as the square of the
Orifice ICDs are similar to nozzle-based
fluid-flow velocity, which increases as the port devices. Backpressure is generated by adjusting
opening diameter decreases.
the number of orifices of known diameter and
Nozzle-based ICDs are self-regulating com- flow characteristics in each tool. The orifices are
pletion components. That is, given the uncer- inserted in a jacket around a basepipe. Another
tainty of permeability variations along the option consists of an annular chamber on a stanhorizontal section of the wellbore, each ICD joint dard oilfield tubular. The reservoir fluid is prowill behave independently of the local heteroge- duced through a sand screen into a flow chamber
neity and fluid type, which may change over time. from which it then flows through parallel tubes to
The former may occur because of compaction or the production string. Like helical-channel versubsidence around the wellbore, and the latter as sions, these tubular ICDs also rely on friction to
OSWIN09/10—Rick, story #2—Figure 04A
a result of the inevitable influx of water or gas.
create a pressure drop that is determined by the
As fluids more mobile than oil, such as water tube’s length and inside diameter. Some recently
or gas, flow into the wellbore at higher velocities introduced ICDs are best described as tubethan that of oil, backpressure at the point of channel and orifice-nozzle combinations.
ingress increases. This slows the flow of formaSome wells may benefit from a recent ICD
tion fluids through high-permeability intervals or innovation with a valve that reacts to an upstream
streaks, preventing water or gas from reaching or downstream change in pressure. The autonothe wellbore ahead of reserves in less permeable mous ICD adjusts the flow area when the pressections of the formation.
sure differential across it changes.
5. Alkhelaiwi FT and Davies DR: “Inflow Control Devices:
Application and Value Quantification of a Developing
Technology,” paper SPE 108700, presented at the
International Oil Conference and Exhibition in Mexico,
Veracruz, Mexico, June 27–30, 2007.
6. Al Arfi SA, Salem SEA, Keshka AAS, Al-Bakr S, Amiri AH,
El-Barbary AY, Elasmar M and Mohamed OY: “Inflow
Control Device an Innovative Completion Solution from
‘Extended Wellbore to Extended Well Life Cycle’,”
paper IPTC 12486, presented at the International
32
Petroleum Technology Conference, Kuala Lumpur,
December 3–5, 2008.
7. Maggs D, Raffn AG, Porturas F, Murison J, Tay F,
Suwarlan W, Samsudin NB, Yusmar WZA, Yusof BW,
Imran TNOM, Abdullah NA and Mat Reffin MZB:
“Production Optimization for Second Stage Field
Development Using ICD and Advanced Well Placement
Technology,” paper SPE 113577, presented at the SPE
Europec/EAGE Annual Conference and Exhibition, Rome,
June 9–12, 2008.
All ICDs are permanent well components and
are rated by their flow resistance. Essentially, the
rating signifies the total amount of pressure drop
created across the device with a reference fluid
property and flow rate. Nozzle- and orifice-type
devices enjoy an advantage over channel ICDs: The
nozzle size and therefore the ICD rating can be
adjusted easily at the wellsite, before deployment,
in response to real-time drilling information. The
designs of ICDs are typically based on predrilling
reservoir models, and changing the rating of
channel- or tube-type ICDs is more difficult, timeconsuming and not easily done on location.
Modeling: Static and Dynamic
Historically, nozzle-type ICDs have been designed
using a ratio of the pressure drop at the device
inlet as calculated by Bernoulli’s equation to the
average formation drawdown pressure derived
from Darcy’s equation. When this ratio is close
to unity, the ICDs are self-regulating.
The designs based on these assumptions are
simple and effective in horizontal wells with relatively high productivity indexes (PIs) and minimal flow restrictions. The same number and size
of ICD nozzles are assigned to each joint of tubing
from toe to heel. This approach usually improves
flow uniformity through the reservoir, counters
much of the heel-toe effect and balances flow
from heterogeneous zones.
But these goals may be achieved at the cost of
overly restricting the flow from high-permeability, high-rate oil zones. Additionally, this method
eliminates flexibility for zonal control and does
not include the effects of variation in zonal porosity thickness, saturation and oil/water contacts.
For more-precise designs, engineers can turn
to modeling using tools such as the Schlumberger
ICD Advisor software. Using steady-state systems,
the experts model wellbore hydraulics to determine tubing and annulus flow, flow direction and
completion-specific flow correlations. Reservoir
flow is determined through PI models.
Incorporating data from offset wells, LWD
tools, geology and other sources, engineers optimize well designs by determining near-wellbore
performance at a specific time. They test various
scenarios and completion designs to balance flow,
decrease water cut, control gas/oil ratios and, by
varying the number of isolation packers per well
section, verify the effects of annular compartmentalization (next page, top right). In doing so,
they are determining the impact of packer density on production in the presence of ICDs.
Finally, they determine the number and sizes of
nozzles to be deployed in each compartment.
Oilfield Review
The advantages of this steady-state modeling
are quick designs, high-resolution near-wellbore
models and quantification of the upside potential
of oil production with decreased water and gas
cut. However, this approach delivers only a snapshot in time and cannot predict or quantify the
value of delaying water or gas breakthrough. This
step requires the investment of considerably
more time and effort to perform dynamic simulations, such as using the Petrel software reservoir
engi­neering workflow in conjunction with the
Multi-Segmented Well (MSW) model of the
ECLIPSE reservoir simulator.
This model treats the well as a series of segments and allows engineers to model independently three-phase flow, liquid-gas holdup and
the implications of using ICDs and flow control
valves over the life of the well. Each modeled segment can be angled upward or downward and can
contain different fluids to account for an undulating well path.
Ideally, dynamic modeling is accomplished
using a full-field geologic model. But often this is
not practical, even with high-performance, parallel computing hardware, because of the long computational simulation necessary to complete the
runs. A more practical solution begins by extracting a sector model from the ECLIPSE full-field
simulation model that can extract flux, pressure
or no-flux boundary conditions to reduce dynamic
simulation time while honoring the geologic heterogeneity and interference from nearby wells.
Reducing the number of geology grid cells
offers more-sensitive runs. Furthermore, the sector model can be combined with the full-field
model. The area of interest is then modified to
refine the grid and upscale from the geologic
model, and the well trajectory is loaded. The
segmented well with ICDs and packers is then
created in the ECLIPSE simulation.
The Sweet Spot
The advantage gained by the ability to quickly
incorporate new data into completions was demonstrated in a field offshore Malaysia. Having
opted, for economic reasons, to drill two long
horizontal wellbores into a target characterized
by a thin oil rim with a gas cap and active aquifer,
the operator included ResFlow ICDs in the completion design. Because they are nozzle-type
devices, it is easy to adjust and optimize them on
location in response to new LWD data without
costing valuable rig time.
Winter 2009/2010
Oil Rate,
bbl/d
Gas Rate,
Mcf/d
Water Rate,
bbl/d
Water Cut,
%
BHP,
psi
698
2,411
23.7
3,794
798
1,263
12.5
3,752
837
762
7.6
3,740
Open hole
7,759
3 x 4 mm, second joint
8,821
3 x 4 mm, joint
9,290
> Packer density impact. By isolating compartments within heterogeneous
formations, it is possible to reduce water cut and sand production
considerably while maintaining or, as in this case, increasing oil production.
Reservoir engineers first test the model for optimum packer density before
determining the number and sizes of ICDs needed for the completion. In this
example, installing three 4-mm-diameter nozzles per joint reduced water cut
to 7.6% compared with 23.7% in an openhole completion. At the same time
production increased from 7,760 to 9,290 bbl/d [1,233 to 1,476 m3/d] without
a significant increase in bottomhole pressure (BHP). When the same nozzle
configuration was used on every second joint, water cut was reduced to 12.5%.
The wells were part of a second-stage development of a mature field; challenges included a
stacked sand reservoir with uncertain dips and
unconsolidated sands. The company also sought
to avoid formation damage during drilling, minimize drilling costs, and maximize production and
drainage of remaining reserves while minimizing
water cut.7
While the horizontal well option was less
costly than an alternative plan that included
drilling three deviated wells, it was technically
more challenging. It required one 2,000-ft
[610-m] lateral and one 1,000-ft [305-m] lateral
to be placed precisely with respect to fluid contacts and reservoir boundaries (below). This
option also required openhole sand screens and
passive ICDs to enable production contribution
from the entire length of the wellbore.
Rotary steerable systems were used to drill
the wells as far from the water contact as possible to delay water production and as close to the
overlying shale boundary as possible to capture
attic oil. An LWD assembly that included a deep
azimuthal resistivity distance-to-boundary tool—
Gas zone
000
–4,
Oil zone
Water zone
–3,875
OSWIN09/10—Rick, story #2—Figure 06
A
B
–3
,75
0
m
750
0
ft
2,500
0
> Well placement. As part of an ongoing field expansion, this small area within a field offshore Malaysia
was targeted for development using one 2,000-ft lateral (A) and one 1,000-ft lateral (B). The thin oil rim
(green) is bounded by a strong waterdrive (blue) and a gas cap (red).Depth contours are labeled in
feet. (Adapted from Maggs et al, reference 7.)
33
Vilje
Production line
Gas lift line
East Kameleon
Alvheim FPSO
Water injection
and disposal line
Umbilical
East riser
base
West riser
base
Kneler A
South
riser base
Boa
Kneler B
Volund
> Layout of Alvheim and Volund fields in the Norwegian area of the North Sea. [Courtesy of Marathon
Petroleum Company (Norway) LLC.]
Production from both wells compared favorably with that from other deviated wells in the
area drilled conventionally through the stacked
sands of the field. However, even including costs
of the additional technology—rotary steering system, LWD and ResFlow ICDs—the overall project
cost was 15% less than it would have been using
traditional well construction methods. In addition, increased sweep efficiency gained by well
placement and ICDs has increased the asset value
by an estimated 100,000 bbl [16,000 m3] of oil.
Actual oil production rate
Predicted oil production rate
Actual water cut
Predicted water cut
30,000
Oil production rate, bbl/d
25,000
80
70
60
20,000
50
15,000
40
OSWIN09/10—Rick, story #2—Figure 07
30
10,000
Water cut, %
the PeriScope bed boundary mapper—was used
to steer a smooth wellbore trajectory.
The longer lateral came online without the
assistance of gas lift at 2,300 bbl/d [366 m3/d] of
oil and a water cut of about 10%. This level of
water production was expected from mobile
water in the oil rim and is not associated with
breakthrough from the water leg. The second
well, drilled updip from the first, required gas
lift to clean up and initially produced about
1,900 bbl/d [302 m3/d] with 20% water cut.
20
5,000
0
Jun 16,
2008
10
Aug 08,
2008
Sept 24,
2008
Nov 13,
2008
Jan 02,
2009
Feb 21,
2009
Apr 12,
2009
Jun 01,
2009
Jul 21,
2009
Sept 09,
2009
0
Date
> Production improvements. In Well 24/6-B-1CH of the Alvheim field, the 13-m oil column with an active
aquifer was produced at a higher drawdown than originally planned. As shown in the graph, the
resulting higher production volumes were achieved without significantly increasing water cut over
predicted values, which is indicative, if not conclusive, that an even inflow profile was achieved.
34
Critical Components
Besides their ability to enhance drainage efficiency and boost cumulative oil recovery, ICDs
offer the industry relatively inexpensive, low-risk
components for technology-driven strategies. They
can be easily added to development programs that
include sand control and horizontal wells.
In the Norwegian sector of the North Sea, engineers at Marathon Petroleum Company (Norway)
LLC concluded that the recoverable reserves in
the relatively thin oil columns of the Alvheim and
Volund fields were directly and consistently linked
to the amount of net pay exposed to the wellbore
(left). To establish maximum contact, Marathon
therefore drilled single-, dual- and trilateral wells
with horizontal sections ranging in length from
1,082 to 2,332 m [3,550 to 7,651 ft].
The Marathon team realized that to fully
exploit the benefits of the correlation of recoverable reserves to net feet of reservoir contact, it was
important that the entire length of the completions contribute to production. Early in the project
they decided to use both ResFlow nozzle-type ICDs
and helical-type ICDs in all production wells—a
total of 10 wells at Alvheim and 1 at Volund.
As a result of this technology-based approach
and the favorable geology, Marathon has increased
its booked reserves at Alvheim from 147 million
to 201 million bbl [23 million to 32 million m3]
of oil and from 196 to 269 Bcf [5.5 billion to
7.6 billion m3] of gas.
The fields have been in production less than
two years, and the completions include numerous
technologies, making it difficult to attribute
specific results to a single methodology. However,
overall water production at the Alvheim floating,
production, storage and offloading (FPSO) facility
is less than originally expected. A good example is
the 24/6-B-1CH well, which has a 13-m [43-ft] oil
column and an active aquifer. The well has been
produced at higher rates than originally planned
without significant onset of, or increase in, water
production (left). Both these outcomes, though
their causes are inconclusive, suggest ICD success
in maintaining an even flow profile.
When one completion planned as a single lateral evolved to a trilateral, engineers also learned
a valuable lesson concerning planning for the use
of ICDs and multilateral installations. Because
the actual completion departed from the original
plan, the flow rate was different than predicted.
The ICDs chosen for these installations were of a
design type that could not be readily changed,
and thus optimized, on location. The result was
gas and water coning earlier than expected in
both laterals.
Oilfield Review
Winter 2009/2010
Simulated flow profile
ICD completion actual flow profile
Heel
Toe
Measured depth
1 ICD
ICD
1 ICD
2 ICDs
Swellable packer
2 ICDs
3 ICDs
3 ICDs
4 ICDs
5 ICDs
> Inflow profile from production log measurements. After installation of ICDs and swellable packers,
production logging tools were run to acquire an inflow profile along the length of the well at low,
medium and high flow rates. The inflow profile shown was obtained with the well flowing at the
medium rate. Crossflow evident in earlier logs has been eliminated and flow contribution is evident
from the entire lateral. The actual inflow profile (green) was very close to the simulated one (red).
(Adapted from Krinis et al, reference 8.)
The well was produced at 6,000 to 7,000 bbl/d
[953 to 1,113 m3/d] for 4 months. A production
log was then acquired. The log data, as well as the
inability to get the tool within 650 ft [198 m] of
TD because of solids-laden mud filling the toe of
the wellbore, indicated the well had not cleaned
up despite the prolonged flow period.
The flow rate was then increased to 9,000 to
10,000 bbl/d [1,430 to 1,590 m3/d] for 4 h and the
well was logged again. The new data indicated an
improved flow profile and the tool was able to
travel an additional 350 ft [106 m]. Four hours
later, the logging tool was run again, this time to
within 50 ft [15 m] of TD (below). The rate was
reduced to the original 6,000 to 7,000 bbl/d and
data from the final logging run indicated a
permanent change had been made to the
inflow profile.
Initial log at 6,000 bbl/d
Initial log at 9,000 bbl/d
Repeat log at 9,000 bbl/d
Repeat log at 6,000 bbl/d
10,000
9,000
8,000
Production rate, bbl/d
A Clean Start
Predictably, it has been observed that the difference in pressure drops between the heel and toe
caused by friction losses in an openhole horizontal well increases with wellbore length. This
disparity can lead to the filtercake being preferentially lifted from the wellbore wall at the heel
and to poor inflow performance caused by correspondingly higher skin at the toe.
Studies have shown that in relatively highpermeability environments, the best cleanup
results—removal of filtercake after drilling or
completion—are obtained through proper chemical treatment and extended flowback with high
rates.11 In 2006 Saudi Aramco completed two test
wells equipped with ICD systems, one in a sandstone formation and the other in carbonate rock.
In the sandstone there were concerns over water
and gas coning through high-permeability
streaks, and the operator sought to decrease the
impact of the heel-toe effect to improve cleanup
and sweep efficiency. The 8½-in. openhole completion included 5½-in. screens with ResFlow
ICD nozzles on every joint of tubing. For compartmentalization and better inflow control, small,
swellable elastomer packers were placed on
every second joint. The horizontal section was
2,540 ft [775 m] long.
Production, bbl/d
Recently, a different operator expanded on
the application of ICD completions, not to counter the effects of uneven inflow profiles but to
counter uneven pressure profiles. In one horizontal well extending more than 5,200 ft [1,600 m]
through a high-permeability reservoir in a large
Middle East field, the pressure differential
between heel and toe was 200 psi [1.4 MPa] with
the higher pressure at the heel.8
An initial production log confirmed what was
expected given the pressure profile: A downward
crossflow of fluids from heel to toe was detected
during a shut-in logging pass. In addition, production logging measurements acquired while the
well was flowing showed water moving downward
from the heel and oil flowing to the surface. Logs
also indicated production was coming from only
the first 10% of the lateral.9
Based on the results of static modeling, the
operator recompleted the well with 22 ResFlow
ICDs and, to segment the well, seven swellable
packers on the production string. Logs acquired
after recompletion indicated that crossflow had
been eliminated and production was coming
from the entire lateral. Water cut was reduced
from 30% to less than 10%, and the actual inflow
profile matched that predicted by the static ICD
model (above right).10
7,000
6,000
5,000
4,000
3,000
2,000
OSWIN09/10—Rick, story #2—Figure 09
1,000
0
9,000
9,300
9,600
9,900
10,200 10,500 10,800 11,100 11,400 11,700
Measured depth, ft
> Cleanup through higher rates. After the logging tool failed to reach TD and
log data indicated no production contribution from the toe after an initial flow
period of 4 months (red), the rate was increased to about 9,000 to 10,000 bbl/d
for 4 h and the production log was rerun. Log data yielded an improved flow
profile, and the tool was able to travel an additional 350 ft (gray). Four hours
later, the logging tool was run to within 50 ft of TD (green). The rate was
returned to about 6,000 to 7,000 bbl/d, and log data demonstrated a permanent
change had been made to the inflow profile (blue). (Adapted from Sunbul et al,
reference 12.)
8. Krinis D, Hembling D, Al-Dawood N, Al-Qatari S,
Simonian S and Salerno G: “Optimizing Horizontal Well
Performance in Nonuniform Pressure Environments
Using Passive Inflow Control Devices,” paper OTC 20129,
presented at the Offshore Technology Conference,
Houston, May 4–7, 2009.
9. Krinis et al, reference 8.
10.Krinis et al, reference 8.
11.Shahri AM, Kilany K, Hembling D, Lauritzen JE,
Gottumukkala V, Ogunyemi O and Becerra Moreno O: “Best
Cleanup Practices for an Offshore Sandstone Reservoir
with ICD Completions in Horizontal Wells,” paper SPE
120651, presented at the SPE Middle East Oil and Gas
Show and Conference, Bahrain, March 15–18, 2009.
35
Standard
Screen
Zone 1
800 to 1,800 mD
5,800
ICD with
ICD with
Target Rate,
Same Nozzle
Different
m3/d
Size, 1.2
Configuration
cm/joint,
in All Zones Nozzle Size
4,604
3,570
3,500
0.9 cm/joint
Zone 2
200 to 500 mD
748
1,233
Zone 3
100 to 2,000 mD
961
1,677
820
800
0.7 cm/joint
3,128
3,200
2.2 cm/joint
3
Total injection rate, m /d
7,509
7,514
7,518
7,500
> Optimizing injector ICD design. The injection rates used in the different
completion scenarios of the Stær structure demonstrate that the injectors
can be optimized based on permeability and nozzle design to obtain the
desired rates in each zone. (Adapted from Raffn et al, reference 13.)
Engineers suspected that the higher rates designing injection projects must consider perrequired to clean up the entire production interval meability contrasts, heel-toe effect, formation
had exacerbated the heel-toe effect in the tradi- damage, creation of thief zones and injectivity
tional openhole completions. Modelers matched changes at the wellbore.13
the production log data to a static reservoir simuJust as they do with inflow control, ICDs
lation and replaced the ICD completion in the address these challenges by balancing fluid outsimulation with a standard screen completion. flow along the entire length of the injection wellThey then increased the rate in the standard bore. If the well has a high-permeability streak,
screen completion to 15,000 bbl/d [2,400 m3/d].
the ICD self-regulating feature prevents a signifiThat simulation indicated an extreme heel- cant increase of local injection rate. This ability
toe effect: The toe was contributing only 25% as to automatically control fluid mobility results in
much production as the heel. By contrast, simu- better water distribution and pressure support
lated ICD completions with 15,000-bbl/d rates and thus enhanced areal and vertical sweep of oil
showed better balance of the inflow, including reserves in all zones. It also delays water breakthrough, and because ICDs can control injection
much higher contribution from the toe.12
These findings are significant in that they pressure and rate, there is minimal risk of nearshow ICD completions allow extended well wellbore fracturing.
These capabilities matched the management
lengths in both these formations without compromising the balancing effect or cleanup efficiency goals of the Statoil team planning the 2004 develin the lower sections of the wells. That result opment of the Urd field—a satellite producing to
allows the operator to contact more formation the Norne FPSO vessel in the North Sea. Placed on
with fewer wellbores without fear of sacrificing production in 2005, the Urd oil field contains two
heterogeneous structures: Svale and Stær, which
cumulative production.
OSWIN09/10—Rick, story
12 and 5.6 mi], respectively, from
are 4#2—Figure
and 9 km [2.5
the main field. The field was developed using three
Reversing Direction
Though they are called inflow control devices, subsea templates and pipelines for oil production,
ICDs are also used to manage fluid outflow in water injection and gas lift. Management goals for
injection wells. In some cases modeling reveals the ICD injection system included
that it is more effective to place ICDs in the injec- •optimizing pressure support and sweep efficiency for all zones
tor well than in the producer. And in many
instances installing the devices in both the injec- •delaying water breakthrough in high-permeability connected zones
tor and producer wells is the best option.
Injector wells often penetrate and give pres- •avoiding fractures that may dominate water
distribution.
sure support to several reservoir intervals with
The Stær structure was completed with one
varying characteristics. To avoid water breakthrough at production wells, reservoir engineers injector containing ICDs and two horizontal oil
producers containing intelligent technology for
control of three zones. The reservoir is divided
36
into two segments; the injector and producer are
located in Segment 1 and the second oil producer
in Segment 2.
The injector is a vertical well drilled through
the Not, Ile, Tilj and Åre 2 Formations and provides sweep and pressure support for two horizontal producers. About 250 m [820 ft] deep, the
injection well is an openhole completion with
ResInject injection control devices, sand screens
and a pack of resin-coated gravel to prevent
annular flow.
Engineers from Reslink and Statoil designed
the system. They modeled injection rates
expected for three zones using different completion techniques: standard screens alone, ICDs of
the same nozzle size and number of nozzles per
joint, and different numbers of ICDs per joint
(left). The team chose to use the same nozzle
configuration along the entire wellbore instead of
specific ICD nozzle sizes and numbers for each
zone. This choice reflected the fact that while different designs in each zone achieved target injection rates, simulations supported maximum
injection rates in the upper zones.14
These simulations were run to evaluate the
economics of using ICD injectors on Stær and to
select the nozzle design. Two static near-wellbore
simulations were used to compare water distribution: The first was based on injection into the
matrix, including its permeability variations,
and the second considered injection into a fractured zone.
In the first case, the upper, high-permeability
zone received an uneven share of the injected
water. However, with ICDs, peak outflow was
reduced by 50% and zones with lower permeability received more water. For the second static
model, a 12-m [39-ft], 20-D layer was added to
12.Sunbul AH, Lauritzen JE, Hembling DE, Majdpour A,
Raffn AG, Zeybek M and Moen T: “Case Histories of
Improved Horizontal Well Cleanup and Sweep Efficiency
with Nozzle Based Inflow Control Devices in Sandstone
and Carbonate Reservoirs,” paper SPE 120795,
presented at the SPE Saudi Arabia Section Technical
Symposium, Alkhobar, Saudi Arabia, May 10–12, 2008.
13.Raffn AG, Hundsnes S, Kvernstuen S and Moen T: “ICD
Screen Technology Used to Optimize Waterflooding in
Injector Well,” paper SPE 106018, presented at the SPE
Production and Operations Symposium, Oklahoma City,
Oklahoma, USA, March 31–April 3, 2007.
14.Raffn et al, reference 13.
15.Tachet E, Alvestad J, Wat R and Keogh K: “Improve
Steam Distribution in Canadian Reservoirs During
SAGD Operations Through Completion Solutions,”
paper 2009-332, presented at the World Heavy Oil
Congress, Porlamar, Venezuela, November 3–5, 2009.
16.Fram JH and Sims JC: “Addressing Horizontal Steam
Injection Completions Challenges with Chevron’s
Horizontal Steam Test Facility,” paper 2009-398,
presented at the World Heavy Oil Congress, Porlamar,
Venezuela, November 3–5, 2009.
17.Fram and Sims, reference 16.
Oilfield Review
Control of the Future
The success of ICDs is now drawing the attention
of producers concerned with inefficient flow
from long laterals. Among these are heavy oil producers. For more than 15 years, steam-assisted
gravity drainage (SAGD) has been the process
of choice for development of fields producing
heavy oil. Despite this history, the process is not
well understood.15 It may be that the current
steam distribution in horizontal injection wells
designed to heat and drive oil to deeper production wells is less than optimal, particularly in
heterogeneous reservoirs.
Besides the common difficulties associated
with creating uniform flow through any reservoir,
two-phase water systems (liquid and vapor) used
in SAGD wells add to the difficulty of control. In
addition to single-phase-flow concerns relating to
fluid-velocity profiles and pressure drops associated with piping configurations, many other factors including flow-regime effects, water holdup,
phase splitting, droplet size, slugging and other
variables are introduced in two-phase flow.16
Typically, SAGD injection liners are slotted
along the entire section—a configuration that
does little to optimize steam distribution. To fight
the heel-toe effect, many operators today use
dual steam conduits in horizontal steam injectors—one landed near the heel of the well and a
second near the toe.
Winter 2009/2010
Production history
Modeled standard completion,
high-permeability channels
Modeled standard completion,
no high-permeability channels
80
70
60
Water cut, %
simulate a fracture. When ICDs were included in
the model, the fracture experienced a waterinjection rate increase of only about 10%; there
was a 10-fold jump when only a standard screen
was used in the same model.
A third evaluation used a full-field reservoir
model to estimate the effect of the improved
water distribution. This evaluation included an
injection well equipped with ICDs in scenarios
similar to those analyzed by the near-wellbore
simulator in the first two cases.
The simulations concluded that given a highpermeability channel, the use of ICDs increased
cumulative oil production by 10% over that
achieved with use of a standard screen alone.
They also showed that with no high-permeability
zone present the ICDs would improve cumulative
oil production by 1% and that the most likely case
was somewhere between the two (right).
In 2008, based on the success of this waterinjection project, Statoil installed another
injection well equipped with ResInject ICDs in
the Svale structure. The well has performed
according to objectives.
50
40
30
20
10
0
0
200,000
400,000
600,000
Cumulative oil production, m3
800,000
1,000,000
> Water-cut models. For the most part, the actual water cut in this well was
lower than predicted by either model. Though the field is in early production,
the improved numbers may reflect enhanced sweep achieved by the use of
ICDs. (Adapted from Raffn et al, reference 13.)
In an effort to better understand SAGD production and find more efficient solutions to its
challenges, Chevron has constructed a surface
horizontal steam-injection facility at its Kern
River field near Bakersfield, California, USA.
Researchers there are focusing on evaluation and
deployment of equipment for accurate and reliable steam placement along laterals in horizontal
injection wells to improve recovery.17
Their proliferation in recent years is testimony to the effectiveness of ICDs. Use of ICDs
has allowed operators to realize full value from
the ability to drill long laterals, thereby exposing
large volumes of the reservoir to the wellbore. In
fact it can be argued that inefficient drainage
owing to uneven flow through the reservoir
threatened to impose economic limits on wellbore length that were far short of the technical
limits. Today’s lengths are measured in kilomeOSWIN09/10—Rick, story #2—Figure 13
ters rather than in meters, as they were less than
a decade ago. —RvF
37