Copyright 2005, Society of Petroleum Engineers

This paper was prepared for presentation at the 2005 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, U.S.A., 9 12 October 2005.

This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Well completion plays a critical role in well design, and more importantly, the performance of the well in its entire life. The major objective for this study is to provide some guidance in the design of completion configuration by a series of simulation with different completions under different flow and reservoir environments. The reservoir inflow and the wellbore hydraulics under complex completion environment will be fully coupled in the study. The most popular completion options, including open hole, slotted liner, inflow control devices (ICD), intelligent well completions (DIACS), perforated cemented liner, wire wrapped screen, ECPs, gravel pack, and frac pack, will first be briefly introduced and reviewed. The performance of the completions will be explored and compared for different wells under different flow conditions, including fluid type, well type, well rate, pressure drawdown, and reservoir geology.

Well performance will then be studied in details by evaluating the total well production, annular flow and flow inside the liner/tubing, pressure profiles along the annulus and along the liner, inflow from reservoir to annulus and fluid transfer between annulus and liner, and so on. Impacts of key parameters like skin factor, wellbore length, well completion configuration, and pressure drawdown, will be investigated.

Introduction Well completion plays a critical role in well design, and more importantly, the performance of the well in its entire life. With more and more advanced well completion options deployed in new wells, especially in the deep and ultra-deepwater environment, the cost and the impact of well completion would be too significant to be ignored. Unfortunately, the details of well completion are normally not taken into account

in most of the current reservoir simulators. Furthermore, there appears a disconnection between reservoir simulators and wellbore hydraulics/tubing performance prediction software in regard to the ability to model complex well hydraulics including an appreciation of the influence on deliverability of reservoir effects and completion design.

The major motivation for the study to be described in the present paper is to evaluate the performance under different completion designs for two newly proposed gas wells and one existing oil production well. In addition, a number of potential factors that may have impacts on well production will also be evaluated. These factors include pressure drawdown, wellbore damage, non-Darcy effect, zonal isolation, wellbore pressure drop, fluid flow along an annulus, well position, and so on.

The Simulation Tool NEToolTM is a commercially available completion modeling and well planning simulation tool. This PC program1, which models production fluids flowing from reservoir, through well completions into a wellbore, is designed to be used for well placement and completion screening and/or design studies where local variations in reservoir properties are important to well performance. It allows fast upscaling and honors any complex reservoir description information from earth model to compute multiphase flow from the reservoir through the well completion, into the wellbore and up to the wellhead. Through alternative well placement, the well behavior can be estimated for the given reservoir description and well completion design. The steady state oil, water and gas production rates as well as production profile along the length of the horizontal wellbore can therefore be calculated. This program fills the gap between conventional reservoir simulators and current well hydraulic simulators. It is also a tool most suitable for analyzing horizontal well production logging data.

Options of the well completion scenarios include openhole, slotted liner, perforated cement liner, wire-wrapped screen, gravel pack, blank pipe, etc. It also can predict performance of intelligent well completions, ICD, in horizontal and multilateral wells. Contribution from each lateral of a multilateral well can be computed. Another unique feature of NEToolTM over the conventional horizontal well in a reservoir simulator is its ability to account for fluid flows in the annulus space between the wellbore and the openhole, in

SPE 96530

An Evaluation of Well Completion Impacts on the Performance of Horizontal and Multilateral Wells L.-B. Ouyang, SPE, and B. Huang, SPE, Chevron Energy Technology Co.

2 SPE 96530

the case of slotted liner and/or wire-wrapped screen completion.

Note that there are a number of limitations associated with the NEToolTM:

Not all the completion options considered in the current study are readily available for simulation in NEToolTM. Some approximation needs to be done to simulate a certain types of completion, like cased hole fracpack.

The fluid flow from bottomhole to wellhead is represented by a VFP or vertical flow performance (lift curves). Simulation with VFP option turned on is found to be unstable under certain circumstances.

Completion Option For any new wells, there are a number of completion options available for selection. Selection of a completion for a new well is typically based on cost, production efficiency, and the ability to handle the potential flow difficulty such as sand production. The cost varies from a completion type to the other, and the production may also change depending on the well and flow conditions.

Different completion designs have been proposed for the two newly proposed gas wells, including openhole gravel pack, cased-hole gravel pack, standalone sand screen, cased hole fracpack, expandable sand screen (ESS). For cased-hole gravel pack and cased-hole fracpack completion, an isolation string may be required.

Schematics for all types of well completion considered in this study are provided in Figures 1 5.

Throughout the paper, the following definition of five completion scenarios is applied:

OHGP: Openhole gravel pack; CHGP: Cased-hole gravel pack with isolation string; SAS: Standalone (prepacked) sand screen (SAS); CHFP: Cased-hole fracpack with isolation string; ESS: Expandable sand screen

The detailed completion parameters for all the above-listed completion options are given in Table 1.

Skin factor is a measure of the amount of additional pressure drawdown to be encountered due to mechanical or turbulent effects. The higher the skin, the larger the extra pressure drawdown, and the lower the well production would be. Mechanical skin is a factor closely related to well completion and independent of flow rate. Typical mechanical skin and its range for each completion type considered are listed in Table 2. In contrast, the skin due to turbulent effects (normally called non-Darcy effect, or non-Darcy skin) primarily depends on flow rate. Non-Darcy skin is typically trivial and thus can be ignored for liquid wells or low rate gas

wells. However, the non-Darcy skin could be as significant as, if not more significant than, the mechanical skin for high rate gas wells like those to be seen in the two wells. More discussion on the non-Darcy skin will be given later in this paper. For the time being, the skin factors listed in Table 2 will be considered as the default values for all the simulations unless explicitly stated.

Validation with PLT Data from Existing Wells A series of simulation runs have been performed for this study. We started with modeling existing wells and conducting comparison with available PLT surveys to validate our simulation.

In overall, the simulation results are found to be quite consistent with those observed via PLT surveys.

It is also found that the wellbore pressure drop is very comparable to the pressure drawdown under the flow conditions (about 80% of the pressure drawdown) for wells in the gas field, indicating the wellbore pressure drop is very important and should be included in the simulation2, 3.

Results and Discussions

Gas Wells As mentioned above, numerous runs of NEToolTM

simulations have been conducted for both new and existing wells in the gas field. In this subsection, results on gas production, water production, and bottomhole pressure over the next 35 years, will be summarized for the two newly proposed wells well A and well B.

Note that the Eclipse simulation output has been applied to estimate the averaged reservoir pressure for the two wells at different times. Both wells have been completed in the same reservoir sands but with different orientation, therefore, the same averaged reservoir pressure as listed in Table 3 were applied.

In addition to the averaged reservoir pressure, phase (gas and water) saturation for each grid block at different times was also imported through an Eclipse output file. Please keep in mind that accurate saturation data is critical to the gas and water predictions to be discussed later in this section.

For each run of the simulation for the two newly proposed gas wells, a tubing head pressure was specified. The tubing head pressure varies slightly with time as shown in Tables 3. Tubing lift curves were generated for each well using ProsperTM with a 7-inch production tubing and the corresponding directional surveys.

Due to the space limitation, only a summary of the simulation results will be given in the present paper.

Figures 6 8 show the change in predicted gas production, water production and bottomhole pressure from

SPE 96530 3

2005 to 2040 under all the five completion options for well A. The results can also be read in Tables 4 6, respectively. The corresponding well Bs gas and water production, bottomhole pressure from 2005 to 2040 are shown in Figures 9 11 and tabulated as Tables 7, 8 and 9, respectively.

Based on the simulation results, the following observations can be made:

Over 100 MMscf/d gas production is anticipated for both well A and well B for all the completions through 2030. However, the gas production from both the wells is posed to decline steadily with time.

No significant change in the gas production is expected for both wells for all the completions without an isolation string. The presence of an isolation string in CHGP (cased hole gravel pack) and CHFP (cased hole frac pack) would substantially limit the amount of gas production due to the significant wellbore pressure drop from toe to heel associated with the small size of the isolation string (Figures 12 and 14). Around 20 30% reduction in the gas production is anticipated with the introduction of isolation string (Figure 6 and Figure 9).

Although a skin of 30 is set for standalone sand screen completion option, no significant reduction in the gas production is expected for this well. However, the wellbore pressure, especially those near the toe, tends to be much lower as compared to those with other completions due to the high skin (Figures 12 and 14).

Water production is not anticipated for well A until 2035 (Figure 7 and Table 5). Nevertheless, once water production initiates, water production rate is expected to increase quickly with time. The amount of water production is dependent upon the type of well completion. Completion with the capability for zonal isolation would stand out should the water production be a major concern.

Little water production is observed for well B until 2020 (Table 8). Several hundreds barrels of water per day would be produced in 2025. Unfortunately, water production would increase quickly with time after 2025 (Figure 10). For well completion with expandable sand screen or ESS, the well would produce around 300 STB/d of water in 2025, 3000 STB/d of water in 2030, and 8000 STB/d of water in 2040 if no remediation measures are taken to reduce water production. The amount of water production is dependent upon the type of well completion. Completion with the capability for zonal isolation should be considered for this well.

Similar to the gas production, the flowing bottomhole pressure largely depends on the completion type. Once again, wells with CHGP and CHFP completion would experience much higher wellbore pressure drop and

thus much lower bottomhole pressure because of the 2 7/8 inch isolation string (Figure 8 and Figure 11).

The initial (year 2005) pressure distribution along the wellbore is illustrated in Figure 12 for well A, while the gas production profiles along the perforated sections are shown in Figure 13. It is clearly seen that majority of gas entry would occur along two sections: 14330 14775 MD and 15160 15340 MD. Little gas entry is anticipated along the 14775 15160 MD section where permeability is relatively low as compared to its neighboring intervals.

It can be easily seen from the wellbore pressure profile as shown in Figure 12 that the wellbore pressure drop from well toe to well heel is quite significant as compared with the pressure drawdown from reservoir to wellbore. As a result, the gas influx from reservoir to the annulus and then to the liner (tubing) will be significantly impacted by the wellbore pressure drop. Highly skewed gas influx profiles are seen in both the influx from reservoir to the annulus and the gas influx from the annulus to the liner. As long as permeability does not change substantially, gas influx would be higher near the heel and lower near the toe.

For well B, the initial pressure distribution along the wellbore and the initial gas production profiles along perforated sections are shown in Figure 14 and Figure 15, respectively. It is observed that majority of gas entry would occur along the entire wellbore section which is due to more uniform permeability distribution along the entire wellbore section.

Oil Production Well In addition to the two newly proposed gas wells discussed

above, an existing multilateral oil producer as illustrated in Figure 16 has been studied. The well consists of an 1180 ft mainbore which was completed with alternating wire-wrapped screens and blank pipes, and two 490 ft openhole laterals (lateral A and lateral B) that were branched out from the mainbore at 526 MD and 757 MD, respectively.

A well history match has been performed on this well with the production data recorded in Sept 2004. The history match run was made with kv/kh = 0.5 and skin = 0. The production profiles from the mainbore and the two laterals are shown in Figure 17. Cross-flow between tubing and annulus along the mainbore was clearly predicted (Figure 17). At the locations of lateral branching out, i.e., 526 MD and 757 MD, the production from the laterals would combine into the flow inside the mainbore, either in the screen or in the annulus. It appears that at 526 MD, where fluid produced via lateral A enters the mainbore, the fluids would flow into annulus; whereas at 757 MD, the fluids from lateral B enter into the screen. The flow behavior at the junctures could be verified by production logging survey once available.

According to the history match, the flow contribution from lateral A is around 112 STB/d (Figure 17) and flow contribution from lateral B (Figure D 14) is about 115 STB/d.

4 SPE 96530

The combined flow stream into the mainbore is 227 STB/d, or approximately 33% of the total well production.

Zonal Isolation via Intelligent Completion For the two newly proposed gas wells, water production appears to be very serious after 2035 for well A and after 2025 for well B. Appropriate actions must be planned and taken right before major water breakthrough to minimize the water production.

Intelligent completion options with zonal isolation capabilities have been evaluated in regard to the reduction in water production. With an intelligent completion, any production from well section deeper than 14995 MD could be blocked to reduce the water production. Figure 18 clearly demonstrates the reduced water production with zonal isolation (ZI) as a result of successful water shut-off (Figure 19) for well A in 2040. The zonal isolation also leads to a slight increase in the gas production.

Uncertainty Issues All the results presented so far are based on the known reservoir conditions, well completion, well trajectory, etc. The conditions may change over time. Besides, certain limitations with the NEToolTM simulator may also affect the simulation results.

In this section, a number of factors that may introduce uncertainty in the NEToolTM prediction for the two newly proposed gas wells will be addressed. Note that this is far from an exhausted list.

Well Trajectory The well trajectories for both gas wells are not finalized

yet and may be subject to change. Any potential changes to the trajectories would affect the results and potentially the observations and conclusions. If a significant modification is made to the trajectories, it is highly recommended that the NEToolTM simulations be repeated to confirm the observations and conclusions.

Rate Dependent Skin For gas production wells (well A and well B), skin can be

treated as two components: mechanical skin and non-Darcy (turbulent) skin. The non-Darcy skin is proportional to flow rate but are less dependent on well completion. It is expected that the non-Darcy skin may be as significant as, if not more significant than, the mechanical skin for the wells under consideration, depending on the gas production rates. The non-Darcy coefficient, or the D factor, should be in the range between 0.01 and 0.05 d/MMscf. If D = 0.03 d/MMscf, then a gas well produced at 100 MMscf/d would incur a non-Darcy skin around 3.

By adding the expected non-Darcy skin to mechanical skin, a total skin can be estimated. The total skin can then be input into NEToolTM to predict gas production. If there is not much difference between the predicted rate and the rate used

for estimating the non-Darcy skin, then the predicted gas rate should be appropriate. However, if there exists significant difference between the two rates, the non-Darcy skin should be recalculated based on the predicted gas rate and the NEToolTM prediction process repeated.

In order to estimate the impacts of the skin on the gas production, a series of simulation runs have been conducted for both wells. Figures 20 and 21 show the normalized gas production rate as a function of the total skin for well A and well B. The normalized gas production rate is defined as the ratio between the predicted production with the specified total skin and the predicted production with zero non-Darcy skin. Figures 20 and 21 display very similar trends, especially for the well production before any significant water production is seen. For well A, a total skin of 10 would reduce the actual gas production by around 5% in 2005 and 2010, whereas it would lead to around 7% reduction in the gas production in 2020.

Once significant water breakthrough occurs (around 2040 for well A and 2030 for well B), non-zero total skin would contribute to more reduction in the gas production, which is also associated with the increase in the water production as demonstrated in Figure 22 for well A. The larger the total skin, the more reduction in the gas production, and the more increase in the water production.

Relative Permeability There are a number of relative permeability sets defined

for the gas field. The relative permeability sets appear to be very different. Any change in the relative permeability curves is expected to affect the NEToolTM predictions in gas rate, water rate, and bottomhole pressure, especially for the cases with potential water breakthrough.

Water Saturation Water saturation distribution, as a function of time, is

determined via the Eclipse simulation. The water saturation distribution plays a critical role in the NEToolTM prediction of water production. Inaccurate water saturation distribution from the Eclipse output would certainly lead to an erroneous NEToolTM prediction of water production from the wells.

Concluding Remarks Gas and water production from two newly drilled wells has been thoroughly investigated with different completion options. The most economical completion option that could lead to the best well performance can thus be identified based on the simulation results. In addition, zonal isolation, wellbore damage, multilateral completion, non-Darcy effect, water production, gas production profile and wellbore pressure profile, etc, have been explored in details in numerous simulation runs.

Oil production from an existing multilateral well has been history-matched. Contributions from the mainbore and from two laterals have been estimated. Oil flow distribution along tubing and annulus has also been evaluated.

SPE 96530 5

Acknowledgement The authors would like to thank Chevron management for permission to publish this paper.

Reference 1. DPT (Drilling Production Technology as): NEToolTM 2.0 Users

Guide, Sept 16, 2004

2. B. J. Dikken: Pressure Drop in Horizontal Wells and Its Effect on Production Peformance. J of Petroleum Technology, 42 (11): 1426 1433, 1990

3. R. A. Novy: Pressure Drops in Horizontal Wells: When Can They Be Ignored? SPE Reservoir Engineering, 10 (1): 29 35, 1995

6 SPE 96530

Table 1. Completion Specifications Parameter OHGP CHGP SAS CHFP ESS

Hole Diameter 9.5 9.5 8.5 9.5 8.5

Screen Basepipe ID, in 4.892 2.441 4.892 2.441 n/a

Screen Basepipe OD, in 5.5 2.875 5.5 2.875 n/a

Perforation Diameter, in 0.4 0.4 0.4 0.4 n/a

Length of Joint, ft 40 40 40 40 n/a

Perforation Density, 1/ft 168 144 168 144 n/a

Casing/Liner ID, in n/a 6.276 6.276 6.276 n/a

Casing/Liner OD, in n/a 7.0 7.0 7.0 n/a

Perforation Hole Size, in n/a 0.512 0.512 0.512 n/a

Shot Density, 1/ft n/a 12 12 12 n/a

ESS ID, in n/a n/a n/a n/a 6.26

ESS OD, in n/a n/a n/a n/a 7.5

Max ESS OD1, in n/a n/a n/a n/a 8.5

Max ESS ID2, in n/a n/a n/a n/a 7.184

Table 2. Mechanical Skin for Different Completions Completion Skin Range of Skin

OHGP 3 0 ~ 10

CHGP 3 0 ~ 10

SAS 30 20+

CHFP 1 -2 ~ 5

ESS 5 2 ~ 10

Table 3. Reservoir and Tubing Head Pressures Year Res P (psi) THP (psi) 2005 3391 1250 2010 3078 1250 2020 2628 450 2030 2270 450 2035 2071 450 2040 1903 450

Table 4. Predicted Gas Production from Well A Year OHGP CHGP SAS CHFP ESS 2005 221 156 216 158 226 2010 197 138 191 140 201 2020 185 127 181 129 190 2030 159 108 154 110 162 2035 143 97 138 99 146 2040 101 78 90 80 99

1 After screen expansion.

2 After screen expansion.

Table 5. Predcited Water Production from Well A Year OHGP CHGP SAS CHFP ESS 2005 0 0 0 0 0 2010 0 0 0 0 0 2020 0 0 0 0 0 2030 0 0 0 0 0 2035 25 6 34 5 32 2040 4632 1725 5323 1549 5413

Table 6. Predcited Bottomhole Pressure for Well A Year OHGP CHGP SAS CHFP ESS 2005 3273 2521 3209 2546 3332 2010 2975 2335 2916 2355 3025 2020 2523 1774 2463 1805 2575 2030 2178 1534 2122 1560 2223 2035 1984 1403 1916 1427 2021 2040 1827 1391 1748 1405 1852

Table 7. Predcited Gas Production from Well B Year OHGP CHGP SAS CHFP ESS 2005 231 156 224 158 235 2010 205 138 199 140 208 2020 193 126 188 127 197 2025 181 118 173 120 184 2030 146 98 132 100 146 2040 92 60 81 61 91

Table 8. Predcited Water Production from Well B Year OHGP CHGP SAS CHFP ESS 2005 9 2 13 2 14 2010 9 2 13 2 14 2020 14 3 20 3 21 2025 296 82 382 74 387 2030 2727 1100 3050 1027 3141 2040 7497 4429 7929 4411 8304

Table 9. Predcited Bottomhole Pressure for Well B Year OHGP CHGP SAS CHFP ESS 2005 3277 2455 3204 2470 3327 2010 2978 2280 2911 2293 3021 2020 2526 1697 2458 1716 2571 2025 2398 1620 2306 1641 2434 2030 2161 1505 2016 1518 2184 2040 1813 1307 1709 1315 1836

SPE 96530 7

Figure 1. Illustration of Openhole Gravel Pack Completion

Figure 2. Illustration of Cased-hole Gravel Pack Completion

Figure 3. Illustration of Cased-hole FracPack Completion

Figure 4. Illustration of Standalone Screen (SAS) Completion

Production Packer

Base Pipe Screen

Open Hole

Polished Bore Receptacle

Bull Nose

= =

= =

= =

GP Packer

Polished Bore Receptacle

Liner Hanger

GP Packer

GP Packer

GP Packer

Sump Packer

Production Liner

Frac Pack

Base Pipe Screen

Liner Shoe

= =

= =

= =

= =

= =

= =

= =

= =

= =

= =

= =

= =

= =

= =

GP Packer

Polished Bore Receptacle

Liner Hanger

GP Packer

GP Packer

GP Packer

Sump Packer

Perforations

Production LinerGravel Pack

Base Pipe Screen

Liner Shoe

GP Packer

Base Pipe Screen

Gravel

Open Hole

Bull Nose

8 SPE 96530

Figure 5. Illustration of Expandable Sand Screen (ESS) Completion

0

50

100

150

200

250

300

Gas

R

ate

(MM

scf/d

)

2005 2010 2020 2030 2035 2040Year

OHGP CHGP SAS

CHFP ESS

Figure 6. Predicted Gas Production for Well A

0

1000

2000

3000

4000

5000

6000

Wat

er R

ate

(STB

/d)

2005 2010 2020 2030 2035 2040Year

OHGP CHGP SAS

CHFP ESS

Figure 7. Predicted Water Production for Well A

0

500

1000

1500

2000

2500

3000

3500

BH

P (ps

i)

2005 2010 2020 2030 2035 2040Year

OHGP CHGP SAS

CHFP ESS

Figure 8. Predicted Bottomhole Wellbore Pressure for Well A

0

50

100

150

200

250

300

Gas

R

ate

(MM

scf/d

)

2005 2010 2020 2025 2030 2040Year

OHGP CHGP SAS

CHFP ESS

Figure 9. Predicted Gas Production for Well B

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

Wat

er R

ate

(STB

/d)

2005 2010 2020 2025 2030 2040Year

OHGP CHGP SAS

CHFP ESS

Figure 10. Predicted Water Production for Well B

Production Packer

Expanded Screen

Open Hole

Polished Bore Receptacle

SPE 96530 9

0

500

1000

1500

2000

2500

3000

3500

BH

P (ps

i)

2005 2010 2020 2025 2030 2040Year

OHGP CHGP SAS

CHFP ESS

Figure 11. Predicted Bottomhole Wellbore Pressure for Well B

2500

2700

2900

3100

3300

3500

14200 14400 14600 14800 15000 15200 15400 15600MD (ft)

Pres

sure

(ps

i)

OHGP CHGP

SAS CHFP

ESS

Figure 12. Initial (year 2005) Wellbore Pressure Distribution for Well A

0

50

100

150

200

250

14200 14400 14600 14800 15000 15200 15400 15600MD (ft)

Gas

R

ate

(MM

scf/d

)

OHGP CHGP

SAS CHFP

ESS

Figure 13. Initial (year 2005) Gas Production along Tubing for Well A

2500

2700

2900

3100

3300

3500

13400 13600 13800 14000 14200 14400 14600 14800MD (ft)

Pres

sure

(ps

i)

OHGP CHGP

SAS CHFP

ESS

Figure 14. Initial (year 2005) Wellbore Pressure Distribution for Well B

0

50

100

150

200

250

13400 13600 13800 14000 14200 14400 14600 14800MD (ft)

Gas

R

ate

(MM

scf/d

) OHGP CHGP

SAS CHFP

ESS

Figure 15. Initial (year 2005) Gas Production along Tubing for Well B

Mainbore

Lateral A

Lateral B

Figure 16. Well and Lateral Trajectory for Well C

10 SPE 96530

0

100

200

300

400

500

600

700

800

0 200 400 600 800 1000 1200Measured Depth (ft)

In-si

tu Oi

l Ra

te in

Tu

bin

g (S

TB/d

)

0

100

200

300

400

500

600

700

800

In-si

tu Oi

l Ra

te in

A

nn

ulu

s (S

TB/d

)

Mainbore Lateral A Lateral B Mainbore, Annular

Figure 17. Oil Production Profile along Mainbore and Two Laterals in Well C

0

1000

2000

3000

4000

5000

6000

Wat

er R

ate

(STB

/d)

SAS -

No

ZI

SAS -

with

ZI

ESS -

No

ZI

ESS -

with

ZI

Scenario

Figure 18. Comparion of Well A Water Production in 2040

0

1000

2000

3000

4000

5000

6000

14200 14400 14600 14800 15000 15200 15400 15600MD (ft)

Wat

er R

ate

(STB

/d)

0

25

50

75

100

125

150

Gas

R

ate

(MM

scf/d

)

Water, no Isolation Water, with Isolation Gas, no Isolation Gas, with Isolation

Figure 19. Gas and Water Production Profile for Well A in 2040

50%

60%

70%

80%

90%

100%

0 10 20 30 40 50Total Skin

No

rmal

ized

G

as R

ate

2005 2010 2020 2030 2040

Figure 20. Reduction in Gas Production due to Skin for Well A

50%

60%

70%

80%

90%

100%

0 10 20 30 40 50Total Skin

No

rmal

ized

G

as R

ate

2005 2010 2020 2030

Figure 21. Reduction in Gas Production due to Skin for Well B

0

50

100

150

200

0 10 20 30 40 50Total Skin

Gas

R

ate

(MM

scf/d

)

0

1000

2000

3000

4000W

ater

R

ate

(STB

/d)

Gas Water

Figure 22. Reduction in Well As Gas and Water Production in 2040 due to Skin

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