Final Report Production Technology 2014 S2 (1)

PRODUCTION TECHNOLOGY GROUP PROJECT

FIELD DEVELOPMENT OPTIONS - CURTIN OFFSHORE FIELD

STUDENTS: AARON ANTHONY (14290345), YINGHSUAN HSIEH (15373438), MOHAK BHANDARI (15632906), DAWEI PAN (15350428), CHRIS RAYNER (4304246), MILENA RADIC (14059740)

DUE DATE: 3RD OF NOVEMBER, 2014

UNDERGRADUATE PROJECT - 2014

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Contents Page Page No.

Letter of transmittal 4)

Background & Introduction 5)

- Objectives & scope 6)

- Assumptions & Constraints 6)

- Deliverables 7)

Executive summary 8)

Main body

Section 1 9)

1.0 Type of Well 9)

1.1 Platform Location 9)

1.2 Problems & Solution to issues 10)

1.3 Drilling issues/Concerns 11)

1.4 Completion issues/Concerns 12)

Section 2 13)

2.0 Well Suspension & Casing/Completions 13)

2.1 Casing program J16, J18 15)

2.2 Completion Strategy 16)

Section 3 17)

3.0 Perforation Interval and Location 17)

3.1 IPR Curve for J18 18)

3.2 Selection optimum Tubing size 19)

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Section 4.0 Analysis Tubing sizes 21)

4.1 Nodal Analysis –Tubing Size 21)

4.2.1 GOR Analysis 23)

4.2.2 Well Head Pressure Analysis 24)

4.2.3 Water Cut Analysis 25)

4.3 Nodal Analysis – Tubing Sizes –ID: 3.068’’ 27)

4.3.1 Well Head Analysis 27)

4.3.2 GOR Analysis 29)

4.3.3 Water Cut Analysis 31)

4.4 Nodal Analysis conclusion 33)

Section 5 34)

5.0 Final Completion Design 34)

Recommendations & Conclusions 34)

Appendices 36)

References 41)

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List of Figures Page No.

Figure 1: Drilling concerns for drilling Shale Formation (petrowiki, 2014) 12)

Figure 2: Temperature Ranges and Pressures (petrowiki, 2014) 13)

Figure 3: List of components and depths for Completion J16 and J18 (Hossain, 2014) 14)

Figure 4: Casing design and depth 15)

Figure 5: Sketch of reservoir intervals 16)

Figure 6: IPR Curve for J18 18)

Figure 7: Standard Tubing Sizes 20)

Figure 8: Nodal Analysis Tubing Sizes 0.824” to 1.995’’ ID 21)

Figure 9: Nodal Analysis Tubing 2.041’’ to 3.958’’ 22)

Figure 10: Liquid production rate vs Tubing Size with changing GOR 23)

Figure 11: Liquid production rate vs Tubing Size with changing Wellhead Pressure 24)

Figure 12: Liquid production rate vs Tubing Size with changing Water Cut 25)

Figure 13: Summary of optimum tubing size ranges for changing GOR, Wellhead Pressure and

Water Cut 26)

Figure 14: Nodal Analysis for 3.068 in tubing size 27)

Figure 15: Values used in Nodal Analysis 28)

Figure 16: Values used in Nodal Analysis with changing GOR 29)

Figure 17: Data from Nodal analysis with changing GOR 30)

Figure 18: Plot of Nodal analysis with changing Water Cut 31)

Figure 19: Data from Nodal analysis with changing Water Cut 32)

Figure 20: Final Completion Design 34)

Figure 21: Considerations/Recommendations for Long Term Production 34)

Figure 22: Schematic of Completions design 35)

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Letter of transmittal: To whom it may concern,

The contribution of each student listed on the cover page has been evenly spread

throughout the project and the final grade for the paper should be spread across

all member equally.

Sincerely

All group members:

1. Aaron Anthony………………………………….

2. Ying-Hsuan Hsieh……………………………...

3. Mohak Bhandari……………………………….

4. Dawei Pan………………………………………….

5. Chris Rayner………………………………………

6. Milena Radic……………………………………..

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Background

The project is designed around the Curtin offshore field located in a water depth of 250ft. The

Field consists of a fully manned steel jacket platform and two reservoirs that overlie one another,

J16, J18. They are separated by a shale interval of 50ft.

J16 is a Hydrocarbon Bearing reservoir with an interval thickness of 100ft. J16 is overlaid by a

sizable gas cap. It has been advised that the production from this reservoir will be insignificant

and production from the lower J18 will be considered as the only viable option for development

J18 reservoir has no gas cap, but it is supported by an aquifer. The Aquifer is expected to provide

some pressure support, which will enable a more effective recovery of the oil. The top of J18 is

4280 ft TVDSS and the oil-water contact is 4390 ft TVDSS. J18 has an interval thickness of 60 ft.

However, there is a 500 ft thick shale interval, which is 700 ft above J16 reservoir and the shale

interval between J16 and J18 is expected to cause difficulties during the Drilling process, as well

as the Completion and Production stages of the field.

The main task in this project is to find a proper and efficient way to produce oil from J18, by

considering options for different types of wells which could be drilled as well as a suitable well

suspension option through IPR and sensitivity analysis, which will be presented in a completion

design for the field.

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Objective and Scope

The objective of this report is to inform the reader about the various issues associated with

Drilling and Completing J18 as well as to provide a recommendation about the most suitable

completion designs which would enable long term production from this well.

This report will identify the types of wells to be drilled as well as the exact ideal drilling location.

A recommendation will also be made in regards to a suitable well completion strategy as well as

the locations of the perforations.

Through the use of Nodal Analysis and IPR curves, the optimum production tubing size will be

recommended and further sensitivity analysis on a range on different factors will be carried out

in order to assist with the development of a sound completion design for the J18 well.

Assumptions & Constraints

Low in-situ stresses

Normal pressure profile

Equipment and Personal are available in the region

The cost of the equipment will be recuperated with a desired payback period once

production begins.

That the fluid properties remain the same throughout the life of the reservoirs.

Constraint of time

Constraint of only basic PVT data

Constraint of not having regional information

Accurate reserves could not be determined due to a lack of volumetric data.

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Deliverables

Out lined in this report is the Well Completions program for the installation of completions

equipment for the Curtin offshore field J18 reservoir.

This report defines the following information:

Type of Well

Platform location

Problems and solutions to solve the drilling issues, completions issues and production

issues

Perforation interval

Nodal Analysis and Sensitivity Study

Completion strategy

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Executive Summary

The purpose of this report is to identify the down-hole Production Technology aspects that are

required to develop the field so that it will produce economically viable amounts of Oil.

The project in essence is broken down into broken down into five sections. These five sections

account for the initial design considerations to the final outlined description, depths of

completions equipment and the Fields Development plan for installation. Excluded from the

report is cost analysis as the project objective is to gain sufficient knowledge of completions

equipment and installation considerations.

Analysis of the data for the project found that two reservoirs are present each with fair to good

reservoir characteristics. The Temperature profile and Pressure Gradient of the reservoir fall into

the Medium Temperature and Medium Pressure region, which has been considered in the

selection of equipment. In addition to this corrosion considerations have also been made with

equipment selection.

The recommended for the J18 well design is as follows:

A Single Deviated well will be drilled into formations J16, J18. The well will intersect both

reservoirs. The Spud location will be off-center to avoid the gas cap and provide a suitable depth

for the Kick off Point. However as directed for simplicity, production will only be from the J18

reservoir.

For the analysis it was assumed that a vertical well would be drilled into the J18 reservoir.

The Casing program will follow standard sizes available in the region as shown in Table 4.The

casing will be of high grade steel and corrosion resistant. It would also be able to withstand in-

situ/ induced stresses and provide axial support to the completion equipment.

The well suspension will consist of a single zone completion model which will isolate the top 30

feet of J18 for production. The completion hardware is listed in Table 3 and it consists of a

cemented bottom, WEG, Packer, SSD. It was discovered through a combination of Nodal and

Sensitivity analysis that optimum production would be through a single tubing of diameter ID =

3.068in OD=3.5in.

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1.0 Type of Well

In analyzing the survey data for the two reservoirs it was identified that the best approach for drilling

and intersecting the reservoirs was to drill a bore hole that:

- Begins off-center of the formations.

- Does not intersect the overlying gas cap.

- Deviated and intersects into the top Reservoir and into the lower reservoir.

This will maintain the integrity of the gas cap and also allows good surface area exposure to the lower

formations. However for the simplicity of the design and analysis, we will consider a borehole that will

be vertical and intersects both formations through the center of the formation.

1.1 Platform location

- For the Deviated Well option (assuming anticline structure) the optimal location for the

drilling rig is off –center from the target interval of the reservoirs. This will lead to the kick

off point (KOP) being reached by the most direct method (KOP=1000m).

- However, for the analysis and design, a vertical well, which intersects the two reservoirs,

will be assumed. The rig should be placed directly above the center of the reservoirs. This

will allow for shortest drilling time to TD and reduce the need for Directional drilling

equipment and materials.

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1.2 Drilling Issues/Concerns

Generally the Issues/concerns that are associated with drilling operations are broken into three

main categories.

1. Mechanical Failure caused by In-situ stress.

2. Erosion caused by fluid circulations

3. Chemical reactions caused by interaction of borehole fluid with formation.

(petrowiki ,2014)

Lithology of J16 & J18 Reservoir is sited as being

Consolidated

Well sorted

Good Porosity & Permeability Sandstone

Minimal Clay content (increasing toward the top)

The major concerns with the drilling of Curtin J16, J18 is the presence of Clay in the formation,

which is increasing upwards. The interval of shale between J16 and J18 (50ft) and the 500ft of

shale that lays approximately 700ft above J16 will be of greatest concern for the Drilling and

Completions phases.

There is a presence of shale in most drilled formation, which contribute to instability. This could

be in the form of washouts and hole collapse, which leads to a reduction in permeability due to

highly sensitive swelling clays.

To combat shale instability an appropriate drilling fluid program should be designed to mitigate

the effect of clays. By adopting such a program the effect on the clays will be minimized and the

integrity of the Reservoir will be conserved.

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1.3 Completions Issues/Concerns

Completion design poses a challenge for any field development. The question is how to best

complete the reservoir so that the maximum volume of Hydrocarbon can be recovered

economically and efficiently.

The major points of concerns in regards to Completion design are:

- Temperature and Pressure effect on equipment installed. As the reservoir temperature is

200℉ and the reservoir pressure is 2000psi, which falls into Medium Pressure and

Temperature region.

- The forces that the down-hole equipment will be subjected to. For instance length changes

due to axial stresses/strains (the equipment must be able to “remain fit for purpose” after

running), temperatures.

- Accurate modeling of flow forces, flow phases and pressures are required to select the

correct flow control devices and completions hardware.

For Curtin Offshore Field completions, primary considerations were given to the following:

(Schlumberger, 2014)

- Liner Hanger System

- Isolation valves

- Packers

- Safety Valves

- Monitoring systems

- Fluid selection

- Sand Control

- EOR

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1.4 Production Issues/Concerns

A wide range of issues could occur when producing from a reservoir. These are listed in the table

below. The project is mainly concerned with the development of Curtin Offshore field; the well

suspension and Casing and Completions strategies, which will lead to the successful economic

operation of the field. Therefore detailed analysis will not be carried out in this project. However

this is an important topic and would be covered extensively in a real life situation.

The major point for the Curtin offshore field is Flow assurance. Ensuring that this system remains

operational till abandonment is paramount for the feasibility of the field and must be scrutinized

to select the method and completion hardware most appropriate. In addition, other equipment

must be preinstalled to combat/correct any issue that may arise during production. This will avoid

early work-over and lost of production time in the event that a problem arises.

The table below summarizes the issues involved with the Drilling, Completions and Production

stages of the Wells lifecycle.

Concern/Issue

Drilling Completions Production

Pipe Sticking Temperature Variation Formation Damage

Loss of circulation Pressure Variation Borehole fluid interactions

Hole Deviation Packer selection Drive Mechanisms

Pipe Failure Elastomer selection Equipment Failure

Bore hole instability Flow control equipment Sand Production

Mud contamination Equipment metallurgy Clay Particle Swelling

Formation Damage Impact of force/length changes Saturation Change

Hole Cleaning issues Operational mode of the well Wettability Reversal

H2S bearing zones Flow Phases Emulsion Blockage

Shallow gas zones Water Blocking

Equipment & personal problems Salt Precipitation

Flow assurance

Figure 1: Drilling concerns for drilling Shale Formation (petrowiki, 2014)

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2.0 Well Suspension & Casing/Completion strategy

Completions Options for J16 & J18

Temperature = 200 degree Fahrenheit

Pressure = 2000psig

Axial Loading:

The equipment must meet or exceed the temperature, pressure, and axial-load conditions created

by the various operating modes anticipated over the life of the well, and material selection should

match the well environment. Most of all, the completion design should be fit for purpose and meet

the production objectives in an efficient and cost-effective manner. (petrowiki, 2014)

The Depth of the well, Pressure, axial loading and the temperature of the well dictate the first

considerations of the correct completions method.

Ranges of Temperature and Pressure for Design considerations:

Temperature (degree Fahrenheit)

Pressure (psi) Abbreviation

T<100 P<3000psi Low Temp / Low Pres

100-300 3000psi -10,000psi Med Temp/ Med Pres

Temp>300 P>10,000psi High Temp/ High Pres

Figure 2: Temperature Ranges and Pressures (petrowiki, 2014)

J18 and J16 have a Temperature of 200 degree Fahrenheit, which lies in the medium Temperature

range, and a reservoir pressure of 2000psig, which is considered Medium Pressure.

Having determined this, only equipment and material that will meet or exceed these

specifications should be used.

Recommended Well Suspension/bottom hole completion (J16, J18):

1. Cemented & cased (see Figure 3)

2. Perforated across the reservoir J18 interval. Top 35m

3. Segregated into separate production Zones. (only the top 35m J18)

4. Mandrels and Packers gauges. WEG (see Figure 3)

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Figure 3: List of components and depths for Completion J16 and J18

Component Function Depth(ft) (TVSS)

Well head and Xmas tree Flow control and isolation -33

Subsurface safety valves (SSSV) Barrier 0

Casing Sizes See Section 2.1

0 - 4330

7’’ linear 0 - 4370

Production Tubing ID:3.068’’ OD:3.5’’

Flow Path for Hydrocarbons 0-4370

Side pocket mandrel Fluid injection 4300

Sliding side door Circulation 1330,3000

Seal assembly Accommodate tubing movement

4100

Packer Annular isolation 4150

Nipple Tubing isolation 4250

Perforated joint Flow alternative entry 4255

Nipple Landing gauges 4360

Wireline entry guide (WEG) Wireline re-entry 4368

(Hossain, 2014)

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2.1 Casing Program for J18

The key considerations involved in the casing program are as follows:

1. Provide support and connection to the reservoir

2. Tolerate Temperature and Pressure ranges

3. Support the completion equipment (axial load)

4. Support changes in In-situ stress, induced stress

5. Corrosion tolerance

6. Portland API Cement Strength

7. Keeping the hole open by preventing the unstable sections from collapsing.

8. Serving as a high strength flow conduit to surface for both drilling and production fluids.

9. Protecting the freshwater-bearing formations from contamination by drilling and

production fluids.

10. Providing a suitable support for wellhead equipment and blowout preventers/ X-tree for

controlling subsurface pressure, and for the installation of tubing and subsurface

equipment.

11. Providing safe passage for running wireline equipment

12. Allowing isolated communication with selectively perforated formation(s) of interest.

Figure 4: Casing design and depth

Component Size (OD) Depth (ft) (TVSS) Conductor pipe (casing) 30” 0-200

Surface casing (casing-1) 20” 0-600 Intermediate casing (casing-2) 16” 0-2600 Production casing (casing-3) 13 3/8 “ 0-4100 Production tubing (casing-4) 9 5/8 “ 0-4330

Liner (Tubing) 7” 0-4370

(Rahman, Sheikh S., and George V, 1995)

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2.2 Completion Strategy

Based on the mentioned issues and concerns that are presented above, the final selection of

equipment and completions strategy is as follows:

1. Vertical well drilled directly into the center of the J18. TD = 4370m

2. The hole will be Cased and Cemented with the top 35feet of J18 being perforated.

(see Figure 3)

3. A single tubing of size ID=3.068in and OD =3.5in will be used. (This choice will be

explained later in the report)

4. Further down hole equipment will be installed to monitor the well and give

options intervention and for EOR at later date. (see Figure 20 & 21)

Figure 5: Sketch of reservoir intervals

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3.0 Perforation intervals and Location The sketch above shows that in J-16, the overlaying gas is 85ft thick on top and the oil layer has

a thickness of only 15ft at bottom. For this thin oil layer, it is quite difficult to consider economical

production. For instance, due to the oil layer being thin, the production rate would be very low.

So in order to increasing the production rate, the well needs to be deviated or even horizontally

inclined to increase the contact surface of the oil layer and well. As a result of this, gas coning is

likely to take place. The prevention or shut-off methods for gas coning should also be devised at

an early stage in order to reduce the need for expensive well intervention activities. As producing

oil from J-16 is deemed to be uneconomical, the decision was made to drill J-18 straight.

As the top of reservoir J-18 is 4330ft TVDSS, the mid depth of the perforations would be at 4345ft

TVDSS (15ft below top of J-18). To calculate the production index, the assumptions made for the

reservoir J-18 are as follows:

Perforation Height = 30ft Permeability = 100mD Oil Viscosity = 1.2cP Oil Formation Volume Factor = 1.3rb/stb Rw = 16/2 = 8in = 0.667ft (Production Casing) Area of J-18 is same as J-16 = 2200 Acres So, Re = 5523ft (assume radial flow) Skin = 0

As there is water support for the reservoir, the steady-state formula for calculating production

index is chosen,

𝑃𝐼 =0.007082𝑘ℎ

μ𝐵𝑜(ln𝑅𝑒

𝑅𝑤−12)

Therefore the calculated 𝑃𝐼 ≈ 1.6𝑠𝑡𝑏/𝑝𝑠𝑖.

By applying Vogel method, the data for IPR curve can be calculated. This was done assuming

the initial reservoir pressure is 2000psig and a bubble point pressure of 2000psig.

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3.1 IPR curve for J18

Figure 6: IPR Curve for J18

The IPR curve above indicates the relationship between the inflow production rate and the

bottom hole flowing pressure based on the assumption currently made for the reservoir. From

the chart, the AOF for this reservoir is around 1780 stb/d.

But this curve also has its limits. As the bubble point pressure is not given, and has been assumed

to be 2000psig, there will be no straight- line section on this IPR curve acting as the oil reservoir

depletion performance does not exist above bubble point pressure. So, if the bubble point

pressure is assumed to be a different value, it will give a different IPR curve plotting.

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3.2 Selection of Optimum Tubing Sizes

Selection of the optimum tubing inner Diameter (ID) is critical to the success of oil production.

The tubing selection is based on the Sensitivity analysis required through the concept of the

Nodal Analysis. The selected tubing should not only fit for the current situation but should also

be good enough to perform for a considerable period. The effect of Gas Oil Rate (GOR), Water

Cut (W-Cut) & Well Head Pressure (P-Out) have been assessed using the computer design

program Pipesim® to give the optimal selection of the tubing.

To complete the sensitivity studies, additional assumptions are required for the estimation.

Based on the assumptions already made in the previous section, the extra assumption would be:

1. Oil Gravity = 35 API

2. Reservoir Temperature = 200F

3. Reservoir Water Salinity = 60000 ppm (S.G. 1.02)

4. H2S content = 10-20ppm

5. CO2 = 0.1%

6. Packer location: 4320ft TVDSS

7. Soil Temperature (surface temperature) = 25degC

8. Initial Well head Pressure = 200psig

9. Initial GOR = 400scf/stb

10. Initial Water Cut = 0%

11. For stimulation, Tubing size chosen are only based on catalogue of API. Tubing

size are as following.

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12. Tubing Size

OD(in) ID(in) OD(in) ID(in)

1.05 0.824

2.875

2.195

1.315 1.049 2.259

1.66 1.38 2.323

1.41 2.441

1.9 1.61

3.5

2.75

1.65 2.922

2.375

1.703 2.992

1.867 3.068

1.995 4

3.476

2.041 3.548

4.5 3.958

Figure 7: Standard Tubing Sizes

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4.0 Analysis of Tubing sizes

4.1 Nodal Analysis - Tubing Size The plot for varying tubing sizes are shown below:

Figure 8: Nodal Analysis Tubing Sizes 0.824” to 1.995’’ ID

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From the analysis, it can be figured out that with the increasing of the tubing size, the operating production

rate increase, and the operating production pressure decrease, due to more fluid requires higher pressure

difference of bottom hole and well head to be lifted up. The minimum stable point is shifting to bottom

right with the tubing size increasing. As the tubing size be up to 3.958in ID, it becomes difficult to recognize

a minimum stable point on the VLP plotting. So if operating with this tubing size, the production will become

unstable and may cause serious problems.

Figure 9: Nodal Analysis Tubing 2.041’’ to 3.958’’

As for choosing the right tubing size for the production, it should not only fit the current situation, but

also need to give relative good production rates for a considerable period of time. Over a long-term period

of production, the reservoir conditions will change, such as a drop in the reservoir pressure; increase in

water cut and increase in gas oil ratio.

Sensitivity studies were carried out for different tubing sizes, different water cuts, GORs and wellhead

pressure conditions. The data and plotting provided are based on “system analysis” and “nodal analysis”

in the pipesim program. The overall analysis for the different tubing sizes was done first, and then 3

particular tubing sizes were chosen to do the nodal analysis. Only the recommend tubing size nodal

analysis will be shown here. The nodal analysis for the other two tubing size will be in included in the

appendix.

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4.2 Overall Analysis

4.2.1 GOR analysis For GOR analysis, the water cut value is assumed to be 0% and wellhead pressure is assumed to

be 200psig.

Figure 10: Liquid production rate vs Tubing Size with changing GOR

In the plot above, the x-axis represents the different tubing sizes (inch for ID) and the y-axis

represents liquid production rate (stb/d). The different data curves represent different GOR

values (scf/bbl). The GOR values picked were from 400scf/bbl as the initial value, then increasing

by a factor of 2 each time until a value of 25600scf/bbl was reached. In this way, a large range of

GOR values can be covered in the estimation. It can be recognized that for most of the tubing

sizes, an increase in the GOR value results in an initial increase in the production rate then a

decrease. By the system calculations, as the GOR value increases up to 25600 scf/bbl, the

production is mostly gas under stock-tank condition. This is proved by the fact that 80.77713%

mass flow will be gas. So, this condition can be regarded as an extreme condition to be the upper

limit for GOR value that an oil production can handle. In order to handle a wide range of GOR

values with a relative high production rate, the Tubing size (ID) value is recommend to be over

2.992in. Larger tubing size provided more liquid production.

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4.2.2 Wellhead Pressure Analysis

For wellhead pressure analysis, the GOR value is assumed to be 0scf/bbl and water cut value is

assumed to be 0%.

Figure 11: Liquid production rate vs Tubing Size with changing Wellhead Pressure

In this plot, the x-axis represents different tubing sizes (inch for ID) and the y-axis represents

changing liquid production rates (stb/d). The different data curves represent changing wellhead

pressures (psig). As the minimum allowable pressure is 200psig, the analyzed pressure range was

from 200psig to 650psig, with a step size of 50psig.

It is easy to observe that with the increasing of the wellhead pressure, the production rate for

each tubing size decreases. The curve for each wellhead pressure indicates that, with the

increasing of the tubing size, the production rate first increases fast, and then the increasing rate

gradually declines. Each curves has a sharp increase at the start before achieving a constant rate.

The end points for the curves of well head pressure 550psig, 600psig and 650psig means that

there will be no stable production at that particular well head pressure with larger tubing ID sizes.

Therefore the recommended range of tubing sizes suitable for long-term production would be

above 2.195in for ID. Larger tubing size gives higher production rate but is not compatible with

high wellhead pressure.

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4.2.3 Water Cut analysis For water cut analysis, the GOR value is assumed to be 0scf/bbl and wellhead pressure is

assumed to be 200psig.

Figure 12: Liquid production rate vs Tubing Size with changing Water Cut

In this plot, the x-axis represents different tubing sizes (inch for ID) and the y-axis represents different liquid

production rates (stb/d). The different data curves represent different WC values (%). The water cut range

is from 0% to 80%. As shown in the plot, with the increase in water cut, the liquid production rate decreases

for each tubing size. When the water cut reaches up to 80%, the system cannot gives a estimated

production value for tubing size over ID 2.75in, which means there is no stable production rate obtainable.

As the data curve for each WC value sharply increases at start and becomes more and more flat, the

recommended tubing size would be between 2.441in to 3.548in ID. Larger tubing sizes generally gives

higher production rate at low water cut, but this advantage gradually disappears and the production rate

even decreases with increasing tubing size at higher water cuts. Larger tubing sizes also cannot handle high

WC.

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For the overall analysis above, the recommendation will be:

Figure 13: Summary of optimum tubing size ranges for changing GOR, Wellhead Pressure and

Water Cut

The chosen tubing sizes for nodal analysis are 2.992in 3.068in and 3.476in ID.

On comparison of the tubing sizes of 2.992in and 3.068in for changing GOR, well head pressure and water cuts, the 3.068in tubing will provides slightly higher production rate in all conditions.

When comparing a tubing size of 3.068in and 3.548in, 3.548in tubing can provide higher production rate compared to 3.068in tubing when in good condition at the start of production life for the well.

Though, for the changing GOR plots, the 3.548in tubing has a better capacity for handling high GOR value, but J-18 does not have gas cap and the aquifer influx is strong hence the GOR value is not expected to be that high.

For the changing water cut and wellhead pressure plots, the production advantage gradually disappears as the wellhead pressure increases or the water cut increases.

For well head pressure plot, the curve for 600psig well head pressure ends at tubing size of 3.068in, which means the 3.548in tubing will not have a stable production rate at the well head pressure of 600pisg.

For the water cut plot, the production rate for 3.548in tubing eventually becomes less than the production rate for 3.068in tubing. This relates to a required long production period, which means the production period turns into a relative undesired situation, leading to water cut increasing and reservoir pressure decreasing over time.

The 3.086in tubing will be sufficient to handle the production flow and provide a relatively good production rate compared to using 3.548in tubing in completion strategy. In regards to planning for long-term production, 3.068in tubing is more suitable than 3.548in tubing.

The recommended tubing size for completion is therefore 3.068in ID with 3.5in OD.

Recommendation

Analysis Tubing size (ID)

GOR 2.992in - 3.548in

W-head P 2.195in - 3.548in

WC 2.441in - 3.548in

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4.3 Nodal Analysis For Tubing Size 3.068inch ID

4.3.1 Well Head Pressure Analysis

Figure 14: Nodal Analysis for 3.068 in tubing size

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The nodal analysis for varying wellhead pressures can be used to indicate how much the reservoir

pressure drop can be tolerated under the assumption made before. As the wellhead pressure

increases, the VLP plot shifts up for the same amount each time (50psig). For reservoir pressure

of 2000psig, the maximum wellhead pressure that is able to give stable production is 600psig for

this size of production tubing. So, this means a minimum pressure difference of 2000 − 600 =

1400𝑝𝑠𝑖𝑔 required to give a stable production. Therefore, if the well head pressure is the

minimum allowable value of 200psig, the minimum reservoir pressure required to give stable

production is 1600psig. So, the allowable reservoir pressure drop for this tubing size is

2000 − 1600 = 400𝑝𝑠𝑖

So, if the reservoir pressure drop becomes more than 400psi, there will be a loss of stable

production and a smaller ID production tubing size is required.

W-head P

(psig)

Stock-tank liquid

at nodal point

(STB/d)

Pressure at nodal

analysis point (psi)

200 1443.781 750.9319

250 1373.937 844.67

300 1293.566 943.46

350 1201.696 1047.2

400 1096.339 1156.786

450 983.4195 1265.465

500 868.4639 1368.625

550 745.0333 1472.525

600 620.9713 1570.994

Figure 15: Values used in Nodal Analysis

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4.3.2 GOR Analysis

Figure 16: Values used in Nodal Analysis with changing GOR

30 | P a g e

From the plot and the table below, it can be seen that the production rate will increase initially

then start decreasing with an increase in GOR. In this analysis it can be seen that the initial GOR

of 400scf/bbl results in a production rate of 1443.781stb/d, but a GOR of 3200scf/bbl can give a

production rate of 1557.381stb/d, an increase of more than 100stb. So, in order to increase the

production rate, gas lift is recommended.

The thick black line in Fig 16 is drawn to estimate the change of the IPR curve due to the maximum

reservoir pressure drop (400psi) during production. The operation point with maximum

production rate is still with a GOR value of 3200scf/bbl. So, the gas lift is recommended to

maintain the GOR value to be around 3200scf/bbl to obtain the maximum production rate.

Figure 17: Data from Nodal analysis with changing GOR

GOR

(scf/bbl)

Stock-tank liquid at

nodal point (STB/d)

Pressure at nodal

analysis point (psi)

400 1443.781 750.9319

800 1525.334 628.9187

1600 1551.445 586.0987

3200 1557.381 576.0551

6400 1528.732 623.4655

12800 1434.908 763.3221

25600 1199.437 1049.647

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4.3.3 Water Cut Analysis

Figure 18: Plot of Nodal analysis with changing Water Cut

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WC (%)

Stock-tank liquid

at nodal point

(STB/d)

Pressure at nodal

analysis point (psi)

Oil Production

Rate (STB/d)

0 1443.781 750.9319 1443.781

10 1407.372 800.8413 1266.6348

20 1360.852 861.352 1088.6816

30 1301.122 934.5234 910.7854

40 1221.548 1025.499 732.9288

50 1114.037 1138.982 557.0185

60 963.1363 1284.171 385.25452

70 762.4047 1458.285 228.72141

Figure 19: Data from Nodal analysis with changing Water Cut

For the water cut analysis, it can be seen from Fig 18 that the production rate decreases as the

water cut increases. This is due to the difference in densities between water and oil. An increase

in water cut, corresponds with an increase in production fluid density. So, the denser the fluid,

the greater the required pressure difference needed to lift up the fluids to the surface. This then

corresponds with a decrease in production rate. Another potential issue caused by increasing

water cut is liquid hold up where the lighter phase is unable to push past the much denser fluid.

The black line is used to indicate the new IPR curve corresponding to a maximum reservoir

pressure drop (400psi) as a result of production. From Fig 18, it can be seen that this curve does

not intercept with the VLP curves corresponding to Water Cuts of 60%, 70% and 80%. The original

IPR curve however intercepts all the VLP curves except the one corresponding to 80% WC. This

means that the capacity of handling water cut is decreasing with a decrease in reservoir pressure

during production. So, in order to make it safe, the water shut off method should to be executed

at a water cut of 50%.

33 | P a g e

4.4 Nodal Analysis Conclusion Based on the assumptions and analysis above,

The recommended production tubing size is 3.068in ID and 3.5in OD. The maximum allowable reservoir pressure drop is 400psi. As the initial GOR value is 400scf/bbl, gas lift equipment should be used to increase the

GOR to around 3200scf/bbl in order to achieve maximum production rate. The water shut off method needs to be executed at a water cut of 50%.

34 | P a g e

5.0 Final Completion Design

The final Design is as follows:

Cased Cement well bore drilled to a depth of 4400 ft SS

Single Tubing of size 3.5 “ OD run to a depth of 4265 ft SS

Sub surface completions equipment of Packers and Mandrels, SSSV

Figure 20: Final Completion Design

Equipment Piece Function Justification Approx. Depth (SSft)

Casing – API sizes Provide Well integrity, and isolation from non-producing formations.

Requirement to provide safety and ensure hole integrity

4330

Completion Tubing Provide Pathway for HC

Needed to connect BH to surface equipment.

4370

Permeant Packer Isolate production Zone

Protect upper Casing, Direct flow to tubing, Isolate pressure

4150

Sliding Sleeves Allow communication- annulus & tubing

Back up for problems that might arise

2 x (1330 & 3000)

Mandrel Infectivity/Circulation Artificial lift, corrosion inhibitor, inj. pt

4300

Nipple Landing Sensor, tool, junk stopper

Monitoring applications

Above WEG

WEG Guide wire line past Good Practice – stop hang ups of tools

4330

* (see Figure 3 for Casing sizes)

Figure 21: Considerations/Recommendations for Long Term Production

Key Issue Possible Solution Completion Option

Pressure Support Depletion EOR Gas Lift Tech or Sub. Pump

Mechanical Failure - Zonal Isolation SSSV

Corrosion/ Scale/ Paraffin Wax /Hydrate

Inhibitors and Preventer Mandrel, SSD

Change in OWC Monitoring equipment Access (wireline)

WEG

35 | P a g e

Schematic of Final Completions Design

Figure 22: Schematic of Completions design

36 | P a g e

Appendix

IPR curve plot data

Q (STB/d) Pwf (psi) Q (STB/d) Pwf (psi)

0 2000 1255.859 987.0918

64.24245 1959.484 1290.918 946.5755

127.3176 1918.967 1324.81 906.0592

189.2253 1878.451 1357.534 865.5429

249.9658 1837.935 1389.091 825.0265

309.5389 1797.418 1419.48 784.5102

367.9446 1756.902 1448.703 743.9939

425.183 1716.386 1476.758 703.4776

481.2541 1675.869 1503.645 662.9612

536.1578 1635.353 1529.365 622.4449

589.8942 1594.837 1553.918 581.9286

642.4633 1554.32 1577.304 541.4122

693.865 1513.804 1599.522 500.8959

744.0993 1473.288 1620.573 460.3796

793.1664 1432.771 1640.456 419.8633

841.066 1392.255 1659.172 379.3469

887.7984 1351.739 1676.721 338.8306

933.3634 1311.222 1693.103 298.3143

977.761 1270.706 1708.317 257.798

1020.991 1230.19 1722.364 217.2816

1063.054 1189.673 1735.243 176.7653

1103.95 1149.157 1746.955 136.249

1143.678 1108.641 1757.5 95.73265

1182.239 1068.124 1766.878 55.21633

1219.633 1027.608 1775.088 14.7

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Nodal Analysis for Tubing size 2.992in (ID)

GOR

W-head P

38 | P a g e

39 | P a g e

Nodal Analysis for Tubing size 3.476in (ID)

GOR

40 | P a g e

41 | P a g e

References

Borehole instability, 2013,SPE.http://petrowiki.org/Borehole instability (accessed 9/28/14)

Completions Systems 2014, SPE.http://petrowiki.org/Completion_ systems#Factors_that _affect_the_

design_of_completion_systems (accessed 9/28/14)

Completions. 14 bakerhughes.2014.http:// www.bakerhughes.com /products -and-

services/completions/well-completions (accessed 9/28/14)

Completions Products. 2014. Schlumberger Services. http://www.slb.com/ services /completions

/completion _products.aspx (accessed 8/10/14)

Hossain, Mofazzal. 2014. “PT Lecture- Completion Basic.” PDF lecture notes.

https://lms.curtin.edu.au/webapps/portal/frameset.jsp?tab_tab_group_id=_4_1&url=%2Fwebap

ps%2Fblackboard%2Fexecute%2Flauncher%3Ftype%3DCourse%26id%3D_71645_1%26url%3D

Rahman, Sheikh S., and George V. Chilingarian. Casing Design-Theory and Practice. Vol. 42. Elsevier,

1995.