IPTC 17171

Application of Nozzle-Based Inflow Control Devices (ICD) in Al-Khafji Field

Mahmoud Abd El-Fattah, Varma Gottumukkala, SPE, Schlumberger; Ahmed Alawi Ahmed Sadah, Tawakol I.
Mohamed, and Subhi Ali Nufaili, Al-Khafji Joint Operations (KJO)

Copyright 2013, International Petroleum Technology Conference

This paper was prepared for presentation at the International Petroleum Technology Conference held in Beijing, China, 26–28 March 2013.

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Abstract
Al-Khafji field, located in the Arabian Gulf, contains an unconsolidated sand reservoir subdivided into two reservoirs (A and
B). The main obstacle in Al-Khafji field is water encroachment due to unfavorably high-water mobility compared to oil;
therefore, the field presents a reservoir management challenge in the form of curbing water production in these relatively
high-permeability sandstone reservoirs. Both reservoirs (A and B) have irregular water-front movement and water
encroachment is dominated by edge-water drive for reservoir A and bottomwater drive for reservoir B. Water
coning/fingering problems are evident even in the crestal regions. This water encroachment problem can be explained by one
or combination of:

 Water movement behind casing

 Water movement along conductive fault planes

Typical Al-Khafji field horizontal wells are completed with cemented liners and perforations. The wells typically water out
during the initial production phase because of the reasons explained previously and limitations on surface water handling
capabilities adds to the problem by preventing the wells from flowing at their full potential.

A new technology for horizontal well completions has been proposed by integrating 350-µm screens with inflow control
devices (ICD) and packers to curb the water production by delaying water breakthrough and managing sand production.
Numerous wells in the field have been completed with a nozzle-based ICD, and the promising results will be discussed
during the course of the paper.

The ICD-completed wells will be analyzed and compared with nonICD-offset wells. The parameters that were used during
the ICD-completion design to overcome the main field challenges will be highlighted. Completion strategy has been changed
in Al-Khafji field based on positive performance results from the ICD-completed wells.

Introduction

Horizontal wells are drilled to maximize the reservoir contact productivity index (PI), and establish linear flow inside the
reservoir for optimum recovery. These horizontal wells also improve sweep efficiency with better conformance of the fluid
fronts. Because of the extended well lengths across the reservoir pay zone, the PI per unit length is much greater in a
horizontal well compared with that of a vertical well, which in turn minimizes the reservoir drawdown and mitigates sand
production in unconsolidated reservoirs while curbing gas and/or water-coning problems. Horizontal wells optimize
development cost and operating costs when properly drilled and completed.
2 IPTC 17171

Most horizontal wells have predominant production/reservoir challenges which need to be addressed based on the type of the
reservoir. In homogeneous reservoirs, extended horizontal well lengths could have a heel-to-toe effect, which hinders the
production from the toe of the well while creating a maximum drawdown at the heel. This condition could mean that
horizontal wells are prone to gas/water coning and an early breakthrough condition. Also, improper cleanup associated with
the heel-to-toe effect could mean that the net/gross will be reduced significantly. Considering a well in a heterogeneous
reservoir, the permeability variations across the horizontal well can vary quite drastically. This means that fluids flowing at
higher rates flow from the high-permeability section while lower rates flow from the remainder of the horizontal section for
the same drawdown imposed (Shahri et al, 2009). This condition will create an uneven fluid contacts sweep across the
horizontal section decreasing the oil reserves. To address all these challenges, proper well placement and completion
techniques should be used for maximum benefit and return on investment. This paper describes the completion techniques
used in Al-Khafji field to mitigate the challenges and presents case studies of wells completed with ICDs.

ICD technology was developed to overcome production challenges in horizontal wells and the technology has been widely
used. An ICD is a flow and pressure regulator that controls flow from the annulus to the tubing by flow restriction through
high permeability areas and stimulating tight areas. The area can be modified based on the production and reservoir
challenges. A typical ICD completion consists of ICD joints with packers that segregate openhole horizontal section into
compartments (Figs. 1 and 2). The main industry drivers supporting the use of ICD completions include:
 Balance inflow along the well
 Delay water and gas breakthrough
 Control water cut
 Reduce/eliminate downhole crossflow and heel-to-toe effect,
 Provide effective initial well clean-up
 Control sand production
 Provide a cost-effective reservoir completion solution (Ouyang 2009; Moen and Asheim 2008)
There are many types of ICDs; i.e., fixed-setting (tube, helical) that are unable to manipulate pressure drops and flow areas at
the wellsite while nonfixed types (nozzle-based ICD) can address the same conditions with minimal installation time. The
advantages of nozzle-based ICDs (Fig. 3) include negligible dependence on viscosity and the ability to manipulate pressure
drops and flow rates for a wider range of applications. A total of 34 combinations/areas can be arranged with a single ICD
joint. Each ICD joint has four ports with four different nozzle sizes that can be varied based on reservoir/well challenges
(permeability, PI, openhole length, well target flow rate, bottomhole flowing pressure, pressure drop across the completion,
and fractured intervals isolation).

To address Al-Khafji field challenges, numerous wells were completed with nozzle-based ICDs. This paper will present ICD
completion design optimization methodologies and results. In addition to discussing the performance of ICD completions
installed in two reservoirs (A and B) compared with offset cemented perforated liner completion wells (non-ICD
completion).

Field Background and Challenges

The sandstone reservoir (A and B) discovered in 1960, were determined to be of the upper Middle Cretaceous geologic age.
The field has been on production for the past 50 years; however the crude oil production commenced in February 1961.
These two reservoirs produce sweet crude oil with 28.0ο API gravity. The subsea depths of oil producing zones range from
4,900 to 5,300 ft. The average reservoir pressures of A and B are 1,974 and 2,378 psig at 5,080 and 5,360 ft ss respectively.
Most of wells in reservoir A are flowing with gas lift (GL) assistance while the remainder of the wells are flowing naturally.
Some of the wells in reservoir B are flowing with electrical submersible pump (ESP) support while the balance of the wells
are flowing naturally. Both reservoirs are continuing to produce above bubblepoint pressure. The daily production from both
reservoirs range from 150,000 to 200,000 BOPD with an average water cut of 18%. The reservoir drive mechanisms for the
two reservoirs are edge water drive and bottomwater drive, respectively.

The main problems for Al-Khafji field are water coning and early water breakthrough. Both problems-relate to the main
challenge in Al-Khafji field i.e., the water breakthrough crests in reservoir A wells, although the reservoir is edge-water
driven (Al-Dhafeeri et al. 2012).
IPTC 17171 3

The Main Challenges in Al-Khafji Field

Early Water Breakthrough

Although the reservoir has been on production more than 50 years, water sources are still considered to be a mystery. Many
different concepts and scenarios have been considered such as channeling behind the casing, highly conductive faults,
channeling through the high-permeability zones, and high-permeability streaks. The high-permeability streaks are better
represented by a natural flow unit or layer that has a much lower resistance to fluid flow than other layers. In such a case,
fluid flowed preferentially through the high-permeability zone and very little fluid was diverted into relatively low-
permeability interbedded zones, which accelerated water production. As a result of this issue, water breakthrough crested in
the edge-water driven reservoir A wells. Excessive water production from production zones, as with the sandstone reservoirs
of high permeability, causes major economic, operational, and environmental problems during oilfield operations. Other
problems affecting production operations include oil reduction, low-flowing wellhead pressure, and the necessity to expand
the capacity of water separation and handling facilities for disposing large volumes of waste water. Furthermore, water
production can also cause secondary problems such as sand production, corrosion, emulsion, and scale formation. If water
flow paths are present, blockage materials and proper installation techniques should be used to reduce water production and
continue oil production.

Bottomwater and Coning

Water channels and water coning are serious problems in reservoir A, while the bottomwater is the main problem in reservoir
B (Fig. 4). Several wells in both reservoirs, especially the vertical wells, suffer from water coning problems because of the
high permeability. As a result, the wells were shut-in due to bottomwater coning because the oil rate was subsequently
reduced and water rates increased to a level not permitted by the company strategy. In such a case, if the water production
could be controlled in both reservoirs, the revenue would be significant.

Near-Wellbore Problems
Poor-quality cement operations, incorrectly chosen perforation intervals and unsuitable completion practices are some of the
wellbore challenges and difficulties the operators face in Al-Khafji field. A poor cement job could be the cause of water
channeling behind the casing, which is one of the most serious problems that increase water production. In addition,
selecting incorrect perforation intervals near the bottom of the water-producing zone, above the gas zone, or adjacent to a
conductive fault or high-permeability streaks in vertical and/or horizontal wells can dramatically accelerate the water
production, which leads to poor conformance and poor sweep and recovery performance. In such case, unless a blocking
agent introduced by cement or chemicals can be applied, the well’s potential is seriously impacted (Al-Dhafeeri et al. 2012).

Water-Cut Effect on the Performance of Artificial Lift Methods.

Two artificial lift methods are used in Al-Khafji field; gas lift and ESP. Both methods help to increase well life but they are
not water production-control tools. Once water breakthrough has taken place, gas-lift efficiency decreases because it cannot
handle excess water production. As well %WC increases the well production potential decreases until the well die. It will be
more critical in ESP case; although ESP can handle larger amount of fluid compared to GL, but when water breakthrough,
ESP accelerate %WC incensement rate because water has higher mobility compared to oil. Both artificial lift methods which
installed in Al-Khafji field need downhole water production control tool.

Macroscopic and Microscopic Heterogeneities

Because of the heterogeneous nature of the rock, fluids tend to follow paths of least resistance which in reservoirs are
macroscopic and microscopic heterogeneities. Both of these heterogeneities can lead to poor sweep efficiency and accelerate
water breakthrough through crossflow, channeling, coning, etc.; therefore, they need to be controlled. The macroscopic
heterogeneity includes layering, high-permeability streaks, natural or induced fractures, and high-vertical and high-horizontal
permeabilities. Furthermore, super-permeability zones can also cause problems related to accelerating water production and
low-sweep efficiency with low recovery. A poor sweeping and low-recovery efficiency could be the result of another serious
problem; i.e., poor cementing operations that represent another form of macroscale heterogeneity. As a result, wellbore fluid
profile modification is needed to produce those wells that suffer from such poor cementing operations, which could be very
profitable if performed correctly.
4 IPTC 17171

Microscopic heterogeneity can be represented as a simple porous feature distribution. In some cases, subtle changes in the
structure of the rock can result in huge changes in the sweep associated with the flow unit even though the porosity remains
at approximately the same value. For example, in some cases, the permeability and porosity of reservoirs are sufficiently high
to produce and make full field developmental strategies; however, after production begins, the sweep through the
homogeneous flow unit is frequently less than expected and leads to low recovery. In such a case, even though there is no
macroscopic problem, the microscopic structure affects the reservoir, resulting in inefficient oil recovery.
Earlier Techniques Implemented to Overcome the Field Challenges
Several techniques were used to overcome Al-Khafji field challenges. Development of the oil and gas production from the
field needs improved capabilities to efficiently reduce and manage produced water and increase the oil and gas recovery. It is
well known that the nature of the oil and gas production wells leads to excessive water production that can adversely affect
the well’s profitability. Currently, there are several methods and techniques that are in use to provide solutions, including:
 Packers and bridge plugs
 Cement squeeze
 Horizontal wells
 Polymer and gel placement

Unfortunately, these techniques do not shut off the water for long periods. Within months to a year, water production returns,
which severely affects the well productivity (Al-Dhafeeri et al. 2012).

Therefore, a conformance technology is required to reduce water production and improve well profitability through increased
well life, reduced lifting and well maintenance costs. In addition, the reservoir management team’s goals include enhanced
reservoir recovery efficiency as well as reduced environmental concerns. Therefore, other techniques need to be applied in
Al-Khafji field such as ICD completions to control water production.
ICD Completion Design Optimization
Every field/well has its own set of challenges; early water/gas breakthrough, unbalanced inflow, downhole crossflow,
fractured reservoir, and complete loss of circulation or surface facilities limitations. The completion design engineer should
be aware of and address all these challenges by prioritizing the production goals of each well. ICD completion design is
performed on a case-by-case basis; i.e., each well has its own set of challenges, requirements, and limitations. The design can
be considered as a critical factor for any well or field development, as this can improve sweep efficiency, delay water/gas
breakthrough, control water production, eliminate downhole crossflow, and isolate loss-circulating zones.

Traditionally, ICD completion design and optimization are performed based on openhole logs (Raffn et al. 2008). (Gamma
ray, porosity, density, resistivity, saturation) and reservoir parameters (derived permeability, relative permeability and PVT
data). Any uncertainties in the data obtained could result in completion design errors. The degree of uncertainty in the data
will determine whether a uniform or a variable nozzle setting is applicable. In general, a uniform nozzle setting with short
compartment length will be efficient with high uncertainty in the reservoir data and vice versa (Abd El-Fattah and
Gottumukkala 2010).

The optimum ICD completion design should have minimum heel-to-toe effect and balanced inflow across the horizontal
section in heterogeneous reservoirs. This balanced inflow across the horizontal section can be achieved by
compartmentalizing the horizontal section with packer design based on permeability, pressure, fluid saturation, viscosity
variations, and managing the pressure drawdown (Pr-Pann) and pressure drop across completion (Pann-Ptub) across the reservoir
section. Care should be taken not to over emphasize production from very low-permeability sections as this could result in
increased pressure drops in prolific sections. The ICD completion design optimization objectives in Al-Khafji field are:
 Balance the influx profile across the openhole section
 Delay early water breakthrough
 Control water production after water breakthrough
 Optimize pressure drop across the completion
 Optimize completion costs
IPTC 17171 5

Often, designers incorporate uniform optimized ICD nozzle settings (same number of nozzles and the size per ICD joint)
across the horizontal interval to avoid the risks of the completion hardware not reaching the required setting depth. Other
optimization techniques include varying the compartment length or using variable nozzle settings (number and size) across
each compartment based on the individual requirements. Nozzle-based ICD design methodology will have its own
preferences when it comes to sandstone and carbonate reservoirs. Because sandstone reservoirs require sand control, the ICD
module includes a sand screen across the entire reservoir section. This design means that all of the ICD joints should be
installed with nozzles to prevent flow convergence into a single joint and compartmentalized accordingly to minimize
annular flow (Gottumukkala et al. 2011). Both uniform and variable nozzle settings were used in the ICD completion design
for the Al-Khafji field wells, which will be explained in details later.

The sandstone reservoirs (A and B) in the Al-Khafji field have different reservoir pressures, which makes the back pressure
critical for ICD completion design. The ICD completion design should have the minimum back pressure; at the same time,
achieve the required water production control.

Another challenge in Al-Khafji sandstone reservoirs (A and B) is unstable shale beds. Al-Khafji team performed a
geomechanical study and recommended the use of heavy-weight drilling fluid (11.5 to 12.5 lbm/gal) when shale beds have
been penetrated. Heavy-weight water-base drilling fluid will cause formation damage and the thick mud cake will increase
the risk of plugging the ICD screen. To overcome this potential ICD screen plugging problem, drilling with nondamaging
heavy-weight drilling fluid (no barite) is recommended. Chemical treatment is also used—displace completion fluid with
formic acid after the completion reaches the desired setting depth.

For completion cost optimization in Al-Khafji field, a comparison was performed between the conventional completion i.e.,
perforated cemented liner and the ICD completion. The results showed that the ICD completion cut costs more than 50% by
saving liner, perforating, and cementing costs, in addition to saving 2.5 to 3 days of rig time. By saving more than 50% of
the completion costs, avoid cement problems in horizontal wells, delay/control water production, and balance production
influx, the ICD completion become the preferred completion technique in Al-Khafji field.

Examples of ICD Completed Wells in Al-Khafji Field

Reservoir A.
A well with a 1,300-ft horizontal 8.5-in openhole was drilled in Al-Khafji reservoir A. Results included 100% net pay,
upscaled permeability ranging from 0.1 to 3 darcy, and an average reservoir pressure of 1,700 psi. To optimize the production
profile across the well’s length and achieve water control in the event of water production, the ICD completion was designed
for a target production rate of 4,000 BOPD.
The main challenges for this well included early water breakthrough from high-permeability streaks along the wellbore and a
sand-production control issue. The actual trajectory for this well added another challenge to the ICD completion design
because the openhole section was not completely horizontal. The drilling entered the reservoir deeper than planned and the
angle then built close to the top surface of reservoir A. Drilling with angle higher than 90 ο makes the difference of + 30 ft in
TVD between the deepest interval (6,900- to 7,030-ft MD) in the open hole and the most shallow interval (well TD) as shown
in (Fig. 5). The problem becomes more challenging because the deepest portion of the well has the highest reservoir
permeability as shown in the openhole permeability profile (Fig. 6)
To overcome these challenges, the high-permeability section was isolated between two swellable packers in one
compartment, which restricted the flow area for the ICD in this particular compartment (two nozzles, each with 2.5-mm
diameters). The remaining openhole section was divided into seven additional compartments. The ICD in those
compartments was equipped with a relatively higher flow area compared with the previous restricted flow area ICDs (three
nozzles, each with a 2.5-mm diameter). The ICD completion showed better influx balance compared with the cement
perforated liner (CPL) completion. This result was due to controlling the production influx in the high-permeability section
and stimulating the relatively tight intervals. The ICD completion balanced the production influx by applying variable
drawdown for each compartment—drawdown will be high against the tight section, allowing for stimulation and less against
the high-permeability section and allowing for production control as shown in Figs. 7 and 8. A water case was simulated
assuming water would break through from the high-permeability interval (6,960-ft to 7,000-ft MD). Simulation results
6 IPTC 17171

showed that the ICD completion reduced the water cut to 15.6% from 69% in the cement perforated liner completion (Fig. 9).
This well has produced approximately 2,600 BOPD with zero WC % for almost one year, compared to offset non-ICD wells
with 60% water cut.

Reservoir B.

A well with an 8.5-in borehole was drilled in Al-Khafji reservoir B with a horizontal openhole length of 2,000 ft. The net
pay was 1,800 ft with an upscaled permeability range from 0.2 to 5 darcy and average reservoir pressure of 2,300 psi. To
obtain uniform and optimized fluid production profiles across the well length and achieve satisfactory water control in the
event of water production, the ICD completion was designed for target production rate of 4,000 BOPD.

The 7,445-ft to 7,715-ft MD interval is a non-reservoir section (shale) and needed to be isolated behind blank pipes (Fig. 10).
This well had contrast in the openhole permeability with relatively high permeability at the toe (Fig. 11). The openhole
section was divided into 11 compartments in addition to a non-reservoir isolated section. A constant ICD flow area/uniform
nozzle setting was used (three 2.5-mm diameter nozzles) for all compartments. The ICD completion showed better influx
balance compared with the cement perforated liner completion due to controlling the production influx in the high-
permeability section at the toe and stimulating the relatively tight intervals. The ICD completion balanced the production
influx by applying variable drawdown for each compartment as shown in Figs. 12 and 13. A water case was simulated
assuming water would break through from the high-permeability interval (8,945-ft to 9,100-ft MD). Simulation results
showed that the ICDs managed to reduce the water cut to 13% from 53% in the cement perforated liner completion (Fig. 14).
This well produced approximately 2,100 BOPD with a 2% WC for almost a one and half years compared with offset
nonICD-completed wells with 35% water cut.

ICD Completion Results in Al-Khafji Field

Many wells were completed using ICDs in Al-Khafji field in both reservoirs (A and B). Reservoir A, ICD wells had %WC
and water reduction ranging from 0 to 15% compared with offset wells that had 60 to 64% WC. The ICD completion
showed good water production control that favorably impacted oil production. Reservoir A ICD wells produced 1.25 times
more oil compared with nonICD-offset wells, while reservoir B ICD completed wells also showed the same positive
performance. Table 1 summarizes the performance results for reservoirs A and B ICD-completed wells.

In general, ICD-completed wells produce with water cut below 15% while offset nonICD-completed wells water cut could
reach 60 to 80%. Many ICD-completed wells produced with zero WC. The Fig. 15 and Fig. 16 plots show ICD-completed
well production test results compared with offset nonICD-completed wells for both reservoirs.

Conclusions

 The ICD completion technology is an effective tool to overcome and mitigate critical production challenges in Al-Khafji
field by delaying water breakthrough and control water production.
 ICD completion is considered to be a cost effective completion solution that reduces openhole completion costs by more
than 50% compared with perforated cemented liner completions.
 Installation of ICDs in Al-Khafji field has improved well performance and productivity when compared with offset non-
ICD completed wells. These results made Al-Khafji team change the reservoir completion strategy and consider the ICD
completion as its default/optimum completion technique for both sandstone reservoirs (A and B).
 The actual test results from ICD-completed wells showed that ICD technology controlled wells %WC by more than 50%
for both reservoirs (A and B) and produced more than twice the amount of oil production when compared to offset nonICD
wells.
IPTC 17171 7

Acknowledgements

The authors would like to thank Al-Khafji Joint Operations (KJO) for actively supporting this work and granting permission to
publish this paper.

Nomenclature

Pann Annulus Pressure Ptub Tubing Pressure

Pr Reservoir Pressure PVT Pressure, Volume, Temperature

References

Abd El-Fattah M., Gottumukkala V., 2010. Design Methodology for Nozzle Based Inflow Control Devices (ICD). Paper
OGEP 2010_148 presented at the 2nd Saudi Meeting on Oil and Natural Gas Exploration and Production Technologies
(OGEP 2010), Dhahran, Kingdom of Saudi Arabia 18–20 December.

Al-Dhafeeri, Abdullah M., Mohamed, Tawakol, and Moawad, Taha M. 2012. Lessons Learned From a Water Shutoff
Technique For Cross Flow Between Two Perforation Intervals in Al-Khafji Field. Paper SPE-158747-PP presented at the
SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 22–24 October.

Gottumukkala V., Abd El-Fattah M. and Ogunsanwo, Oloruntoba 2011. Design Methodology for Nozzle Based Inflow
Control Devices (ICD). Paper presented at the Passive Inflow Control Technology Meeting (PICT), Houston, Texas, 5–6
May.

Moen, T. and Asheim, H. 2008. Inflow Control Device and Near Well Bore Interaction. Paper SPE 112471 presented at the
SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, 13–15 February.

Ouyang, L.B., 2009. Practical Consideration of Inflow Control Device Application for Reducing Water Production. Paper
SPE 124154 presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 4–7 October.

Raffn, A.G., Zeybek, M., Moen, T., et al. 2008. 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, Texas, 5–8 May.

Shahri, Ali M., Kilany, Khalid, Hembling, Drew et al. 2009. Best Cleanup Practices for an Offshore Sandstone Reservoir
with ICD Completions in Horizontal Wells. Paper SPE 120651 presented at the SPE Middle East Oil & Gas Show and
Conference, Kingdom of Bahrain, 15–18 March.
8 IPTC 17171

Figures

Fig. 1—ICD application in homogeneous reservoirs Fig. 2—ICD application in heterogeneous reservoirs

Fig. 3—Nozzle-based ICD joint with fluid passing through the Fig. 4—Al-Khafji field reservoirs (A and B)
nozzles water drive mechanisms

Fig. 5—Actual trajectory profile for reservoir A ICD-completed well

IPTC 17171 9

Fig. 6—Openhole permeability profile for reservoir A ICD-completed well

Fig. 7— Oil influx profile for reservoir A ICD-completed well

Fig. 8— Drawdown and pressure drop across completion profile for reservoir A ICD-completed well
10 IPTC 17171

Fig. 9— water case water influx profile for reservoir A ICD-completed well

Fig. 10— Actual trajectory profile and completion for reservoir B ICD-completed well

Fig. 11— Openhole permeability profile for reservoir B ICD-completed well

IPTC 17171 11

Fig. 12— Oil influx profile for reservoir B ICD-completed well

Fig. 13— Drawdown and pressure drop across completion profile for reservoir B ICD-completed well

Fig. 14— water case water influx profile for reservoir B ICD-completed well
12 IPTC 17171

3000
3000 2800 2557
2500
2500

Production, B/D
2000 1800
2000 1600
Production, B/D

1200
1500
1500
900
1000
1000
500 0
500 0

0
0
Reservoir "A" well_1 Offset well_1 Reservoir "A" well_2 Offset well_1

oil Water oil Water

Fig. 15—Reservoir A ICD completed well test results compared with offset nonICD wells

6000 5900
6000 6000

5000 5000

4000
Production, B/D

Production, B/D
4000

3000
3000 2070
2000 1142
2000 1100 887
761
733
1000 0
1000 0
0
0 Reservoir "B" Offset well_1 Offset well_2
Reservoir "B" well_1 Offset well_1 well_2
oil Water oil Water

Fig. 16—Reservoir B ICD completed well test results compared with offset nonICD wells

TABLE 1—PERFORMANCE COMPARISON BETWEEN ICD-COMPLETED WELLS AND OFFSET WELLS (A

AND B)

Reservoir A Reservoir B
Water-cut Range – ICD wells 0 ~ 15% 60% 0 ~ 16% >50%
Water-cut Range – NonICD-offset wells 60 ~ 64% 35 ~ 80%
Oil Production Rate Range – ICD wells (B/D) 2560 ~ 2910 125% 2100 ~ 6000 170%
Oil Production Rate Range –NonICD-offset wells (B/D) 900 ~ 1535 1000 ~ 1965