Artificial Lift System Design, Optimization and Cost Estimation · 2018. 7. 16. · Pump. The...

REPUBLIQUE TUNISIENNE Ministère de l’Enseignement Supérieur et

de la Recherche Scientifique

Université de Gabès

GRADUATION PROJECT REPORT

Presented to obtain the

National Diploma of Chemical-Process

Engineering degree

Realized by:

JENDOUBI Riadh

Subject :

Artificial Lift System

Design, Optimization and Cost Estimation

Defended on July the 14th, 2018 in front of the committee:

Mr. RJEB Skandar President

Mr. HANNACHI Ahmed Supervisor

Mrs. BEN ALI Samia Member

Mr. FADHEL Imed Guest

Academic Year: 2017/2018 GCP 2018-45/60

Ecole Nationale d’Ingénieurs de Gabès Département de Génie Chimique -

Procédés

ابسقبالمدرسة الوطنية للمهندسين الهندسة الكيميائية أساليب قسم

i

Dedication

To the sake of Allah, my Creator and my Master.

To my great teacher and messenger, Mohammed (May Allah bless and grant him), who taught us the purpose of life.

To the memory of my late father, Mr. Jendoubi Noureddine, May Allah rest his noble soul, who always supported me, whatever path I took.

To my loving mother, Mrs. Azizi Mbarka, for her encouragement and unconditional affection, whatever things I did.

To my dear little brothers, Mr Jendoubi Marouane and Mr. Jendoubi Mohamed Majdi, for standing by my side in times of need.

To all of my friends, especially Mr. Saadi Seddik and Mrs. Marouani Chaima

I dedicate this modest work.

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Acknowledgments

I am extremely fortunate to be involved in an exciting and challenging project which has

enriched my life and gave me the opportunity to look at the Horizon of Technology.

Sincere thanks to the members of the jury: Mr. REJEB Skander and Mrs. BEN ALI Samia for taking time out of their busy schedule and assessing my work. It is an honour to have my work

evaluated by such educators.

Special thanks to the School staff for their hard work as well as their professionalism supporting the student’s best interests.

I would like to express my deep sense of gratitude and respect to my dear supervisor Mr. HANNACHI Ahmed for his excellent guidance, suggestions and constructive criticism. I feel

proud that I'm one of his engineering students.

I’m also grateful for the affectionate support extended by Mr. FADHEL Imed , as my supervisor during our stay together at ETAP and for sharing his wide experience on petroleum production engineering. His support and suggestions helped me a lot to complete the project successfully.

I think this opportunity to express my heartfelt gratitude to Mrs. DALHOUM Rym, for her thoughtful advice and useful discussions.

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Abstract In an effort to increase oil production and guaranteeing a competitive position simultaneously, in an industry where environmental regulations continue to increase, several studies are conducted aiming to optimize oil recovery rates. Multiple artificial lifting systems have been explored, some have led to higher recoveries but with additional costs. Other techniques have failed to reach the set objective. This study is about modelling an already set artificial lifting system based on a JET Pump. The optimization of oil production using a new lifting system with an Electrical Submersible

Pump (ESP) was conducted. Finally, an economical study is provided to estimate the cost of the solution implementation. Keywords: Oil, Artificial Lifting, JET Pump, ESP, cost effective.

Résumé Afin d’augmenter la production de pétrole et simultanément garantir une position concurrentielle, dans une industrie soumise aux réglementations pour la protection de l'environnement, plusieurs études ont été menées dans le but de maximiser l’exploitation et la production des puits de pétrole en augmentant leurs récupérations. Plusieurs systèmes de récupération ont été explorés, certains d'entre eux avaient réussi à des recouvrements plus élevés mais ont été très coûteux. D’autres techniques n'avaient pas réussi à atteindre l'objectif fixé. Cette étude comporte la modélisation d'un système d’activation artificielle déjà mis en place, la JET pompe. En outre, l'optimisation de la production de pétrole en concevant un nouveau système d’activation qui est l'ESP. Enfin, une étude économique est fournie comme guide pour choisir le système approprié et rentable. Mots Clés : Pétrole, Activation Artificielle, JET Pompe, ESP, Rentable.

ملخص

في محاولة لزيادة إنتاج النفط وضمان مكانة تنافسية في صناعة تواصل زيادة الأنظمة لحماية البيئة، تم إجراء عدة دراسات . وقد تم أيضا استكشاف أنظمة استرجاع متعددة، اآبار النفط على أكمل وجه من خلال زيادة قدرات إنتاجهتهدف إلى استغلال

والتي أدى بعضها إلى استرداد أعلى ولكن كانت مكلفة للغاية. بينما فشلت تقنيات أخرى في الوصول إلى الهدف المحدد. تتناول المضخة النفاثة كذلك تحسين إنتاج النفط من خلال تصميم نظام رفع جديد هذه الدراسة محاكاة نظام رفع اصطناعي مثبت وهو

وهو المضخة الغاطسة الكهربائية. وأخيرا، تم توفير دراسة اقتصادية كدليل لاختيار النظام المربح المناسب والفعال من حيث التكلفة

الغاطسة الكهربائية، مربح الكلمات المفتاحية: نفط، نظام استرجاع اصطناعي، المضخة النفاثة، المضخة

iv

Symbols

Boi: Formation volume factor [m3/m3]

Cp: Heat capacity or thermal capacity [BTU/lb/F]

�� : Average reservoir pressure [psia]

Pwh: Pressure at the wellhead [psia]

Pwf: Flowing pressure at the bottom node [psia]

Soi: Connate water salination [%]

ΔPupstream: Pressure loss due to upstream components [psia]

ΔPdownstream: Pressure loss due to downstream components [psia]

ΔP: Total pressure drops [psia]

ΔPf: frictional forces [psia]

ΔPg: gravitational energy change [psia]

ΔPk: kinetic energy changes [psia]

φ: Porosity [%]

v

Abbreviations

ALS: Artificial Lift System AOP: Absolute Open Flow

BPD: Barile Per Day

BHP: Bottom Hole Pressure

CAPEX: Capital Expenditures

EOR: Enhanced Oil Recovery

ESP: Electrical Submersible Pump

FDP: Field Development Plan

GL : Gas Lift

GOR: Gas Oil Ratio

HP: Hydraulic Pump

ID : Internal diameter

IPR: Inflow Performance Relationship

JP: JET Pump

LSE: Laarich South East

MLD : Makhrouga Laarich Debech Concession

OD: Outside Diameter

OOIP: Oil in Place

OPEX: Operating Expenditures

PVT: Pressure, Volume and Temperature

PCP: Progress Cavity Pump

SRP: Sucker Rod Pump or Beam Pump

STB: Stock Tank Barrel

SODEPS: South Permit Development and Exploitation Company

TRAPSA: Tunisian Sahara Pipeline Transport Company

VLP : Vertical Lift Performance

vi

Units

Psi: Pound-force per square inch

Bpd: Barrel per day

Ft: feet

°F: degree Fahrenheit

Sm3: Standard cubic meter

API : American Petroleum Institute gravity

sp. Gravity: Specific gravity

ppm: Parts per million

°C: degree Celsius

m3: Cubic meter

cp: centipoise

STB: Stock tank barrel

MMscf : Million standard cubic feet

lb: Pound

Hz: Hertz

$: US Dollar

Bbls: Barrels

M$: Million Dollars

K$: Thousand Dollars

vii

Contents

DEDICATION ............................................................................................................................................................................. I

ACKNOWLEDGMENTS ............................................................................................................................................................. II

ABSTRACT .............................................................................................................................................................................. III

SYMBOLS................................................................................................................................................................................ IV

ABBREVIATIONS ...................................................................................................................................................................... V

UNITS ..................................................................................................................................................................................... VI

CONTENTS ............................................................................................................................................................................. VII

LIST OF FIGURES ..................................................................................................................................................................... IX

LIST OF TABLES ........................................................................................................................................................................ X

GENERAL INTRODUCTION ........................................................................................................................................................ 1

CHAPTER I. LITERATURE REVIEW ...................................................................................................................................... 2

I.1 THE OILFIELD LIFE CYCLE .......................................................................................................................................................... 2

I.1.1 Exploration phase ................................................................................................................................................... 2

I.1.2 Appraisal phase: ..................................................................................................................................................... 2

I.1.3 Development planning: .......................................................................................................................................... 3

I.1.4 Production phase: ................................................................................................................................................... 3

I.1.5 Decommissioning: .................................................................................................................................................. 4

I.2 ARTIFICIAL LIFT ...................................................................................................................................................................... 4

I.2.1 The need to the artificial lift: .................................................................................................................................. 4

I.2.2 Artificial lift systems: .............................................................................................................................................. 5

I.2.3 Sucker Rod Pump system: ....................................................................................................................................... 5

I.2.4 Hydraulic Pump System: ......................................................................................................................................... 6

I.2.5 Progressive Cavity Pump: ....................................................................................................................................... 7

I.2.6 Gas Lift:................................................................................................................................................................... 8

I.2.7 Electrical Submersible Pump: .................................................................................................................................. 9

I.3 WELL DERIVABILITY AND NODAL ANALYSIS ................................................................................................................................. 11

I.3.1 Introduction: ......................................................................................................................................................... 11

I.3.2 Nodal analysis: ..................................................................................................................................................... 11

I.3.3 Inflow Performance Relationship (IPR) ................................................................................................................. 12

I.3.4 Vertical Lift Performance (VLP) ............................................................................................................................. 14

I.4 CLASSIFICATION OF RESERVOIR FLUIDS ...................................................................................................................................... 15

I.4.1 Dry Gas ................................................................................................................................................................. 16

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I.4.2 Wet Gas ................................................................................................................................................................ 16

I.4.3 Gas Condensate .................................................................................................................................................... 16

I.4.4 Volatile Oil ............................................................................................................................................................ 16

I.4.5 Black Oil ................................................................................................................................................................ 17

I.5 PRODUCTION AND SYSTEM ANALYSIS SOFTWARE PROSPER .......................................................................................................... 17

I.6 PETROLEUM PRODUCTION OPTIMIZATION: SENSITIVITY ANALYSIS PARAMETERS ................................................................................. 18

I.7 LAARICH CONCESSION OVERVIEW .......................................................................................................................................... 18

I.8 CHAPTER CONCLUSION: ......................................................................................................................................................... 19

CHAPTER II. JET PUMP MODEL SETUP ...............................................................................................................................20

II.1 WELL MODELLING WITHOUT ARTIFICIAL LIFT SYSTEM ..................................................................................................................... 20

II.1.1 Input Data............................................................................................................................................................. 20

II.1.2 PVT data ............................................................................................................................................................... 20

II.1.3 Well Data .............................................................................................................................................................. 20

II.1.4 Setting up the model in PROSPER ......................................................................................................................... 21

II.2 WELL MODELLING WITH ARTIFICIAL LIFT SYSTEM ........................................................................................................................... 31

II.2.1 Options Summary ................................................................................................................................................. 31

II.2.2 Sensitivity analysis ................................................................................................................................................ 32

II.3 CHAPTER CONCLUSION: .......................................................................................................................................................... 37

CHAPTER III. ESP MODEL SETUP ....................................................................................................................................38

III.1 ARTIFICIAL LIFT SELECTION CRITERIA .................................................................................................................................... 38

III.1.1 Artificial lift system standards .............................................................................................................................. 38

III.1.2 Artificial lift system choice .................................................................................................................................... 39

III.2 LASE#2 WELL MODELLING WITH ESP .................................................................................................................................. 40

III.3 ECONOMICAL EVALUATION ................................................................................................................................................ 42

III.3.1 Introduction .............................................................................................................. Error! Bookmark not defined.

III.3.2 ESP Case Study .......................................................................................................... Error! Bookmark not defined.

III.4 CHAPTER CONCLUSION: .................................................................................................................................................... 45

GENERAL CONCLUSION ..........................................................................................................................................................46

BIBLIOGRAPHY .......................................................................................................................................................................47

APPENDICES ...........................................................................................................................................................................48

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List of Figures

Figure 1: Surface equipment of Jet Pump ....................................................................................... 6

Figure 2: Subsurface Equipment of Jet Pump................................................................................. 7

Figure 3: ESP configuration.......................................................................................................... 10

Figure 4: The locations of the nodes ............................................................................................. 12

Figure 5: Inflow and outflow curve at a specific node ................................................................. 13

Figure 6: Typical tubing performance curve ............................................................................... 15

Figure 7: Geographical location .................................................................................................... 18

Figure 8: PVT Data before Matching ........................................................................................... 24

Figure 9: PVT Data After Matching ............................................................................................. 25

Figure 10: Downhole Equipment Summary ................................................................................. 27

Figure 11: Downhole Equipment Sketch ...................................................................................... 27

Figure 12: IPR data input main screen .......................................................................................... 29

Figure 13: IPR Curve .................................................................................................................... 30

Figure 14: IPR/VLP curve intersection (State zero) ..................................................................... 30

Figure 15: Water Cut Curve .......................................................................................................... 33

Figure 16: Water Cuts/ GOR curve .............................................................................................. 34

Figure 17: Sensitivity Analysis Results ........................................................................................ 36

Figure 18: Jet Pump Boundaries ................................................................................................... 36

Figure 19: Higher Reservoir Pressures with ESP ......................................................................... 40

Figure 20: ESP calculations with no risk of cavitation ................................................................. 41

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List of Tables Table 1: Options Summary ........................................................................................................... 21

Table 2: PVT Data ........................................................................................................................ 23

Table 3: Laboratory Data .............................................................................................................. 24

Table 4: Deviation Survey ............................................................................................................ 26

Table 5: Geothermal Gradient ...................................................................................................... 28

Table 6: Average Heat Capacities................................................................................................. 28

Table 7: IPR Data Input ................................................................................................................ 29

Table 8: JET Pump Data Entry ..................................................................................................... 32

Table 9: Sensitivity Analysis on Various Water Cuts .................................................................. 32

Table 10: Sensitivity Analysis on various Water Cuts and GOR values ...................................... 34

Table 11: Sensitivity Analysis on various pressure values ........................................................... 35

Table 12: surface considerations ................................................................................................... 38

Table 13: Operating considerations .............................................................................................. 38

Table 14: ALS operating conditions ............................................................................................. 39

Table 15: Recapitulative Table: Reservoir Pressure/Production Rate (ESP) ............................... 40

Table 16: ESP Data ....................................................................................................................... 41

Table 17: CAPEX Expenses ......................................................................................................... 43

Table 18: Reserves Estimation...................................................................................................... 44

Table 19: Recovered and Remaining Volumes ............................................................................ 44

Table 20: OPEX Expenses ............................................................................................................ 45

Table 21: Economical Balance ..................................................................................................... 45

1

Riadh Jendoubi 2017/2018

General Introduction

No one can deny the importance of oil as well as petroleum products in our daily life. Besides

being the origin of multiple geopolitical conflicts, ‘Black Gold’ as it is called provides mankind

it’s essential needs in energy in addition of various uses in many fields such as the medical,

cosmetic and agricultural domains. But, oil production faces logical obstacles that requires an

intervention to assure a continuous but yet efficient production in a leading competitive industry.

Thus, comes the need to artificial lifting systems.

In Tunisia, the Oil& Gas industry, controlled, operated and supervised by the "The Tunisian

Company of Petroleum Activities- ETAP" which is a public enterprise created by Law 72-22 of

March 10, 1972 and allowing the state to increase its control and its active and direct participation in

the various activities of the oil industry by conducting all petroleum studies and managing the national

oil wealth as well as supplying the country’s needs in crude oil and gas.

This project is considered as an important duty for our petroleum production engineering at the

ETAP and its importance lies within the management of oil and gas concession operations, of which

ETAP is a partner, by checking and verifying the reports given by foreign companies as well as the

verification of data and calculations in order to make sure that the rights of the coming generations are

in fact guaranteed and well governed.

This repost contains mainly three chapters. The first chapter is called “Literature Review” and it

comes back on general definition and terminologies of the petroleum industry. Also defining the

equipment and industrial installation that will be used later on. The second chapter, “JET Pump

Model Setup “, presents the use of modelling software in the design of a producing oil well and

the modelling of the installed artificial lifting system. For the final chapter “ESP Model Setup”, it

is dedicated to the optimization of oil production by choosing the wise and appropriate alternative

and manipulating various parameters. Also, a cost estimation is provided in order to evaluate the

expenses and expected gains.

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Chapter I. Literature Review

This Chapter contains general definitions and terminologies used in the petroleum industry. Also

defining the equipment and industrial installation that will be used later on in our study as well as

the mathematical tools of numerical calculations.

I.1 The Oilfield Life Cycle

I.1.1 Exploration phase

Since the late 1800’s and while looking for oil, major discoveries have been made all around the

world. Although, it is likely that any future finds are in fact smaller, more complex fields, appraisal

wells can now be sited more accurately thanks to the development of new techniques increasing

the exploration's efficiency. Managing exploration assets represents a major task because, in

addition of promising geological conditions presenting the existence of hydrocarbons, the host

country’s political and fiscal conditions must be favourable for the rentability of the entire cycle.

Among these conditions we can mention, spatial distance to future markets, the existence of an

infrastructure, and availability of a talented workforce. Normally, exploration investments are

made long ago before there is any opportunity of producing crude oil. Commonly, a company must

work for many years on a precise location before entering the production phase. During this period

and prior to spudding the first well, the geological history will be studied with carrying a working

program such as field work, magnetic surveys, gravity surveys and seismic surveys (J.

Economides, et al., 1993).

I.1.2 Appraisal phase:

After encountering hydrocarbons by the exploration well, and in order to obtain an assessment of

the potential of the find, considerable effort is required to present a picture containing the shape,

size and at last the accumulation’s productivity. The Scenarios are:

• Proceeding with development and generating income within a short time. The profitability

of the project is at risk if the field appears later on to be smaller larger or than thought

ahead, the facilities will be over or undersized.

• Continuing with optimizing the technical development. delaying the "first oil" from the

field by several years. And assuring simultaneously the profitability’s improvement.

3


Reducing the uncertainties is purpose of development appraisal, in particular producible volumes

contained within the formation. After gathering the adequate data for the initial estimation, we

have to define the development options of the field. The study’s objective is to present various

technical options and choosing the most economical among them, also containing the subsurface

development options, the process design, equipment sizes, and the evacuation and exporting of the

oil. Giving in the end a wide overview of all the requirements, opportunities and risks accompanied

by a cost estimate and planning schedule.

I.1.3 Development planning:

After formulating and executing a field development plan used as a key document to achieve

required agreements on the activities of a new field, or extension to an existing one. The purpose

of The field development plan is serving as conceptual project specification for the field facilities,

the operational and maintenance strategy to support the investment proposal. The FOP (Field

Development Plan) is divided into multiple stages from which we can mention:

• Objectives of the development

• Petroleum engineering data

• Description of engineering facilities Cost and manpower estimates

• Budget proposal

• Project planning

After completing the field development plan (FOP), the next steps are:

• Facilities design

• Procurement of the materials of construction

• Facilities Fabrication

• Facilities Installation

• Plant and equipment Commissioning

I.1.4 Production phase:

The first commercialised quantities of hydrocarbons flowing from the oil well declares the

commencement of the production phase generating the first cash flow used to pay any previous

expenses. The most important step is to minimise the time between the first stages of an exploration

project and the ''first oil'' and it is usually based on the expected production profile depending on

the driving force in the reservoir. The production profile determines the required facilities and the

number of drilled casings and it is divided into:

4


• Build-up period: New drilled producers are brought on stream.

• Plateau period: A typical period of two to five years by maintaining the production rate.

• Decline period: During this final period all producers will witness declining production.

I.1.5 Decommissioning:

In order to achieve the decommissioning of a field or installation, we have to:

• reduce the operating costs.

• increase hydrocarbon throughput.

Maintenance and operating costs represent the major expenditure in field life and they are related

to the required staff operating hardware running the facility. As decommissioning approaches,

EOR is the remaining mean after primary production. Ultimately, the field is decommissioned if

it can’t sustain running costs.

I.2 Artificial Lift

I.2.1 The need to the artificial lift:

Lacking the needed reservoir pressure which assure producing oil up to the surface, oil wells all

around the world are in fact unable to produce at economic rates without assistance. This condition

may be the result of pressure depletion overtime, by reservoir mechanism, or be caused by low

original reservoir pressure. So, operators equip the wells with artificial lift systems (ALS) to

produce the desired economical rate [2].

To achieve the lower BHP, several artificial lift systems can be used with a positive displacement

downhole pump, like a beam pump, a progressive cavity pump and an electrical submersible pump.

It could be achieved with the gas lift in which the fluid density in the tubing is lowered and

expanding gas helps to lift the fluid.

To realize the maximum potential from developing oil field, the optimum artificial lift method has

to be selected. The artificial lift methods must consider different parameters, like geographic

location (onshore& offshore), capital costs, operating costs, deviation surveys, reservoir fluid

characteristics (PVT…), well productivity index, reliability…

Also, the equipment and services available from vendors can easily affect the ALS selection. If,

the best lift method is not selected, such factors like long term servicing costs deferred production

during workovers (especially hard workovers), and excessive energy costs (poor efficiency) could

reduce the net present value of the project. Further to Schlumberger statistics, 90% of the active

oil wells use artificial lift systems, however 10% lift naturally.

5


I.2.2 Artificial lift systems:

The most widely used artificial lift in the oil and gas fields are: Gas Lift (GL), electrical

submersible pump (ESP), progress cavity pump (PCP), beam pump or sucker rod pump (SRP) and

Hydraulic pump (HP) (Akthar , et al., 2014).

I.2.3 Sucker Rod Pump system:

I.2.3.1 Basic operation:

The sucker rod pumps are the most widely used form of artificial lift. A rod pump typically consists

of a prime mover, gearbox, walking beam, sucker rod strings and a pump. The dominant types of

rod pumping are the walking beam type or simply beam pumping. This type of artificial lift uses

a positive displacement plunger pump and a surface driving unit that converts the rotary movement

of the motor with mechanical linkage including a pivoted walking beam.

The need for producing deeper and deeper wells with increased liquid volumes necessitated the

evolution of long stroke beam pumping. Several different units were developed with the common

features of using the same pumps and rod string as in the case of beam pump units but with

substantially longer pump stroke length. (Jahn, et al., 1998)

The desired long strokes did not permit the use of a walking beam, and completely different driving

mechanisms had to be developed. The basic types in this class are distinguished according to the

type of surface drive used, as given below:

• Pneumatic Drive

• Hydraulic Drive

• Mechanical Drive Long Stroke Pumping.

I.2.3.2 Sucker Rod Pump components:

The individual components of a Sucker Rod pumping system can be divided in two major groups:

surface and downhole equipment.

Advantages:

• High system efficiency

• Economical to do maintenance and repairs

• Flexibility of production adjustment

Limitations:

• Limited to low production volumes

• Demands a wide surface space

6


• Limited to onshore applications

I.2.4 Hydraulic Pump System:


Hydraulic pumping is a proven artificial lift method that has been used since the early 1930’s in

several thousand oil wells, and the number of hydraulic installations in increasing yearly. It offers

different systems for handling a variety of well conditions, like depth, deviation survey, tubing and

casing. The Hydraulic pumping system takes liquid from the surface (known as power fluid) and

puts it through a reciprocating triplex piston pump to increase its pressure, and then injects the

pressurized liquid down hole through a tubing string. The downhole Jet pump converts the

pressurized power fluid to a high velocity Jet through the nozzle that mixes directly with the

reservoir fluids, with lower pressure, which is accelerated by the throat. In the turbulent mixing,

momentum and energy from the power fluid are added to the produced fluid in the throat. The

homogenous mixture fluid (power fluid +reservoir fluid) go up to the surface through the annulus

after increasing its pressure by the pump.

I.2.4.2 Components:

The hydraulic pumping system surface equipment are shown in (Figure1):

Figure 1: Surface equipment of Jet Pump (Fares, 2016)

Also, the subsurface equipment is shown in (figure 2):

7


Figure 2: Subsurface Equipment of Jet Pump (Fares, 2016)

Advantages:

• Deviated wells & multiwall production from single surface package

• Highly flexible in adjusting to changing production rates.

• Able to produce at higher rates from great depths.

• Chemicals can be added to the power fluid to control corrosion, paraffin and scaling

Limitations:

• Production rate limited by the bottom hole pressure.

• high pressure surface line requirements (2500 -4000 psi)

• Conditioning of the power fluid is required to ensure a clean power fluid.

• Limited ability to tolerate solids in the production fluids.

I.2.5 Progressive Cavity Pump:


PCP systems normally consist of a surface drive, drive string and down-hole progressive cavity

pump. The PC pump consists of a single shaped rotor which turns inside a double helical elastomer

stator.

The result is a non-pulsating positive displacement flow with a discharge rate proportional to the

size of the cavity, rotational speed of the rotor and the differential pressure across the pump.

I.2.5.2 Advantages & Limitations:

The general advantages of using PCP systems can be summed up as follows:

8


• PCPs are able to produce high viscous fluids.

• As there is only moving part in PCPs, there is no sand problem in this system.

• Existence of free gas does not reduce the efficiency of PCP. Also, gas anchor is installed

in well completions.

• Capital and operating expenses are low of this system.

• PCPs handle very well in abrasive fluids, paraffin plugging and scaling.

• High Overall system energy efficiency, typically in the order of 55 to 75 % range.

PCP systems, however, also have some limitations and special considerations:

• PCPs are limited in producing high volume of liquid. The available maximum limit is

nearly 5000 bpd.

• Also, PCPs are limited in depth; the depth limit is 4000ft.

• Volumetric efficiency decreases with the high amount of produced gas.

• Poor temperature handling (operating temperature range is 75°F to 150°F)

• Sensitivity of fluid environment

I.2.6 Gas Lift:


Gas lift is classified the most known artificial lift method that uses an external source of high

pressure gas for supplementing formation gas to lift the well fluids. Unlike AL methods, the gas

lift is widely used in offshore lift. The gas lift method is applicable in highly deviated, high GOR

wells and fluids with high sand content. It is based on theory to reduce the back pressure by lighting

fluid column in the well (V. Nickens, et al., 2003)

With gas lift method, the production is increased with the reduction of the bottom hole pressure

by injection of compressed gas though the annulus or orifice that installed in the tubing. So, two

impacts could be resulted; the gas expansion in the liquid phase, and the second is lighting the oil

density which causes decrease in the hydrostatic pressure and helps it lift to the surface.

The main steps of the gas lift operation could be summarized as follow:

1. Compression of the gas at the surface and transportation to the appointed wells.

2. The compressed gas is injected to the annulus or orifice through gas lift valves.

3. Injected gas lifts reservoir fluids to the surface.

4. Gas and liquid is separated in the separator and after separation gas is again compressed or

transported to the sales manifolds.

9


The main parts of gas lift system are; station for gas compression, injection manifold, injection

chokes, surface controllers, injection valves and chamber that installed in down hole. The figure

below presents view of these parts (Hernández, 2016).


The major advantages of Gas Lift are:

• This method is capable of handling high volume of solids easily.

• Production rate is very high in this method. The maximum production rate could reach

50000 bpd.

• As it was discussed above, it could be changes from continuous gas lift to intermittent gas

lift flow as reservoir pressure declines to a certain level.

• Gas lift method could be installed in urban locations.

• High gas content in produced liquid makes beneficial for this method.

• GL is applicable in high deviated and offshore wells.

The general limitations of using Gas Lift can be summed up as follows:

• High volume of gas is required to lighten the fluid column, although this amount of gas

may not be always available.

• Emulsions and high viscous liquid creates problems in gas lift operations.

• Unlike other ALS, energy efficiency is lower in GL.

• Corrosive gas could make problems in production such as damaging tubing/casing system.

• High paraffin content in the produced liquid could make severe problems in production.

• Freezing and hydrate problems could be occurred in manifold systems. (P.E., 2017)

I.2.7 Electrical Submersible Pump:


The electrical submersible pump, typically called an ESP, is a widely efficient and reliable artificial

lift method in the world for lifting moderate to high volumes of liquid from wellbores. These

pumps are mainly used in operations ranging between 150 to 20000 bpd.

This type of pump is consisted of two main parts: surface component that includes motor

controller, transformer ad surface electric cable, and the second part include the pump, the motor,

the seal section and the gas separator (Woods & James F. Lea, 2017).

10


The operation of ESP is similar to any other industrial electric pump. Electric cables provide

electric energy to the down-hole motor. These cables are attached on the tubing. Electric motor

and pump directly connected each other by shaft.

The key parameter is the outside diameter of the down hole components. Outer diameter mainly

ranges between 3.5 and 10 inches. Pump length ranges is between 40 and 344 inches.

ESPs are mainly applied in the wells with high productivity index. Casing and tubing sizes are also

important in the design of the subsurface components. All these factors influence on the fluid flow

rate. Tubing size and flow rate is used to calculate and determine the total dynamic head (TDH).

The different components (Surface+ subsurface) are shown in (figure3).

Figure 3: ESP configuration (Takacs, 2018).


General advantages are listed below

• The most efficient lift methods on a cost per barrel basis.

• High rate and high depth capability: 100 to 60000 bpd, including high water cut fluids.

• Working in high temperature wells (above 350 °F) using high temperature motors and

cables.

• The pumps could be modified to lift corrosive fluids and sands.

• ESP system could be used in high angle and horizontal wells if placed in straight or vertical

sections of well.

11


The limitations of Electric Submersible Pump are summarized below:

• Electric power availability.

• The higher pulling costs (Hard workover and production losses)

• Limited adaptability to major changes in the reservoir.

• Limited using for high viscosity fluid.

I.3 Well Derivability and Nodal Analysis

I.3.1 Introduction:

The capacity of an oil well to deliver either liquid or gas as a function of physical pressure is called

“derivability”. after combining the well inflow and outflow performances, petroleum engineers

can determine afterwards the derivability of a well. the prediction of an achievable flow production

rate from a precise reservoir with specific characteristics, is in fact the main purpose of the

derivability analysis.

I.3.2 Nodal analysis:

The application of nodal analysis to oil producing systems in the analysis of its performance which

is affected by various interacting components. In Nodal Analysis, the system is divided in two

parts considering a specific point in the system (node) as shown in (figure 4). All components

upstream of the node constructs the inflow section and all the components downstream of the node

constructs the outflow section (Yabada, 2017).

The flow rate through the whole system can be determined once the following requirements are

satisfied:

1. Flow into the node equals flow out of the node.

2. At a single node, only one pressure exists.

The pressures of both reservoir and separator or wellhead, are fixed. Since the node has a unique

pressure, the following expressions can be used:

�� − �� = ��

��ℎ + �� = ��

Where, Pr: the average reservoir pressure, psi

Pwh: the pressure at the wellhead, psi

ΔPupstream: the pressure loss due to upstream components, psi

ΔPdownstream: the pressure loss due to downstream components, psi

12


Figure 4: The locations of the nodes (J. Economides, et al., 1993)

I.3.3 Inflow Performance Relationship (IPR)

I.3.3.1 Productivity Index

First of all, the ability of the reservoir to deliver fluids to the production well has to be examined.

The productivity index (PI) is the measure of the ability of the well to produce fluids [8]. The

productivity index is generally measured during a production test on the well by translating the

coordinates of the operating point (intersection IPR/VLP curves) as shown in (figure 5). The well

is shut-in until the static reservoir pressure is reached. The well is then allowed to produce at a

constant flow rate of q and a stabilized bottom-hole flow pressure of Pwf. This type of flow

theoretically represents a semi steady-state type of flow. Since a stabilized pressure at surface does

not necessarily indicate a stabilized Pwf, the bottomhole flowing pressure should be recorded

continuously from the time the well is to flow. The productivity index is proved to be a very useful

13


tool in Petroleum Engineering in order to predict future performance of wells, since, during a

well’s lifespan, flow regimes are approximating the pseudo steady-state ones.

Figure 5: Inflow and outflow curve at a specific node (Fares, 2016)

I.3.3.2 Factors affecting the IPR

IPR is influenced by parameters related to the reservoir. It is already mentioned that the solution

node is set bottomhole in order to separate the system from the components related to the reservoir

and the components related to the flow in the tubing up the surface. The most notable components

affecting an IPR curve are the following:

Rock Properties

Fluid Properties

Reservoir Pressure

Well Geometry

Well Flowing pressure

14


I.3.4 Vertical Lift Performance (VLP)

One of the major factors affecting the production performance of a well is the pressure loss in the

tubulars. As much as 80% of the total pressure loss in a flowing well may occur in lifting the fluid

to the surface, while the rest is lost in the reservoir. Vertical lift performance expresses the

bottomhole flowing pressure as a function of liquid rate in the wellbore during the production of

reservoir fluids

I.3.4.1 Pressure drop calculations

Generally, the total pressure drops in a well is the summation of the pressure drop due to frictional

forces (ΔPf), gravitational energy change (ΔPg) and kinetic energy changes (ΔPk), with the last one

to be omitted as its value is usually negligible compared to the previous two sources

�� = �� + �� + ��

I.3.4.2 Tubing Performance Curve

the solution node, in a system analysis of a well, lies bottomhole. The generation method of the

inflow performance curve is already analysed. The outflow performance is also necessary to

estimate the bottomhole flowing pressure Pwf which is one of the most important tasks in

Petroleum Production Engineering. This can be easily done, by using the following method. For

various flowrates and for a fixed wellhead pressure, the total pressure loss can be calculated for

the whole length of the production tubing. The outcome of this approach is the Tubing Performance

curve (or else known as VLP curve) and its importance lies on the fact that it captures the required

flowing bottomhole pressure needed for various liquid rates [9]. The VLP depends on many factors

including PVT properties, well depth, tubing size, surface pressure, water cut and GOR. A

schematic example of a VLP curve is shown in (figure 6)

15


Figure 6: Typical tubing performance curve (Fares, 2016)

I.3.4.3 Factors affecting the VLP curve:

Some of the factors affecting the vertical lift performance of the well are:

• Production Rate.

• Well Depth.

• GOR.

• Tubing Diameter.

• Water cut.

• Restrictions (Scale, waxes, etc).

I.4 Classification of Reservoir Fluids

A reservoir contains gas if its temperature is higher than the fluid critical temperature, otherwise

it contains oil. The depletion of reservoir will result in retrograde condensation in the reservoir if

the reservoir temperature lies between the critical temperature and the cricondentherm, whereas

no liquid will form if it is above the cricondentherm. The oil in a reservoir with a temperature close

16


to its critical point is more volatile than that at a lower temperature. A small reduction of pressure

below the bubble point, in a reservoir with a temperature just below the fluid critical temperature,

may vaporise half the oil volume. It is evident, therefore, that the location of reservoir temperature

on the phase diagram can be used to classify reservoir fluids. (Ibrahim, 2017)

I.4.1 Dry Gas

Dry gases are predominantly composed of methane and non-hydrocarbons such as nitrogen and

carbon dioxide. Note that the gas remains single phase from the reservoir to the separator

conditions. Water, however, may condense at the surface conditions due to the gas cooling. PVT

tests in the laboratory are limited to the gas compressibility measurement.

I.4.2 Wet Gas

A wet gas is mainly composed of methane and other light components with its phase envelope

located entirely over a temperature range below that of the reservoir. A wet gas, therefore, will not

drop-out condensate in the reservoir during depletion. The separator conditions lie, however,

within the phase envelope, producing some condensate at the surface. Gas fields in the Southern

North Sea are good examples of this type of reservoirs. As no condensate is formed in the reservoir,

material balance equations for a dry gas are equally suitable for a wet gas. The only PVT test

required at the reservoir conditions is the gas compressibility measurement. Separator tests are

generally conducted to determine the amount and properties of the condensed phase at the surface

conditions.

I.4.3 Gas Condensate

The presence of heavy hydrocarbons expands the phase envelope relative to a wet gas, hence, the

reservoir temperature lies between the critical point and the cricondentherm. The gas will drop-

out liquid by retrograde condensation in the reservoir, when the pressure falls below the dew point.

Further condensation from the produced gas also occurs at separator conditions due to cooling.

I.4.4 Volatile Oil

Volatile oils have many common features with gas condensates, but as they contain more heavy

compounds they behave liquid-like at reservoir conditions. The phase envelope of a volatile oil is

relatively wider than that of a gas condensate, with a higher critical temperature due to its larger

concentration of heavy compounds. The reservoir temperature is near the critical temperature;

hence, volatile oils are referred to as near-critical oils. Note that iso-volume lines are tighter and

17


closer near the bubble point curve. A small reduction of pressure below the bubble point vaporises

a significant fraction of the oil, hence the name "volatile oil".

I.4.5 Black Oil

Black oils, or ordinary oils, are the most common type of oil reserves. The name does not reflect

the colour, but to distinguish it from the volatile oil. The oil is generally composed of more than

about 20 moles % heptane and heavier compounds. Its phase envelope, therefore, is the widest of

all types of reservoir fluids, with its critical temperature well above the reservoir temperature. The

quality lines are broadly spaced at reservoir conditions with separator conditions lying on relatively

high-quality lines. The above characteristics lead to a low shrinkage of oil when produced.

(Danesh, 1998)

I.5 Production and System Analysis Software PROSPER

I.5.1 Introduction:

Prosper, a part of the integrated production modelling toolkit (IPM package), is used in the design

and optimisation of oil well performance (Tetoros, 2015). This software is by far the industry’s

standard well modelling pioneer with biggest petroleum operators. It is also involved in building

well models with the most reliable and consistent standards. It was created with ability of

addressing all aspect of well bore modelling (PVT: fluid characterisation), also VLP curves

correlations (flowline/tubing pressure loss calculations) and finally IPR (inflow curves of oil

reservoirs). Providing the unicity of matching options, enhancing PVT, multiphase flow

correlations and also IPR measured field data). and again, presenting the most consistent well

model built to exploit the prediction feature (sensitivity runs and AL design). Prosper is also able

to calculate detailed surface pipeline design and performance optimization, oil flow regimes,

stability of pipeline, ... (Petroleum, 2012)

Prosper petroleum applications:

• Optimise, design and modelling of well completions.

• Optimise, design and modelling of Piping sizes and shapes.

• Diagnose, optimize and design of GL, HP, ESP and JP wells.

• Generating lift curves used in the simulation of oil wells.

• Pressure losses calculations all along flowline but also in chokes and wells.

• Prediction of flowing temperature.

• well performance monitoring for real time interventions in the required remedial action.

18


• Black oil model built-up model for all types of petroleum products.

I.5.2 Petroleum Production Optimization: Sensitivity Analysis Parameters

Well performance calculations and performing sensitivity runs are provided by PROSPER with a

wide range of variable used in the generation of lift performance curve. Using a 3-Variable system

or a 4-Variable system is the recommended method to calibrate the required models and profiles.

Among these variables we can mention:

• Reservoir Pressure

• Reservoir Temperature

• Water Cut

• Gas Oil Ratio

• Water Oil Ratio

• First Node Pressure

• Tubing/Pipe Diameter

• Downhole Equipment

• Surface Equipment (Yabada, 2017)

I.6 LAARICH Concession Overview

Figure 7: Geographical location (Fares, 2016)

19


the LAARICH concession is an onshore field located within the MLD sector, Tataouine, South of

Tunisia with a total area of 197 km2. The principle play concept for the Laarich permit is oil. The

production is assured by nine drilled wells: LA#1, LA#2, LA#3, LASE#1, LASE#2, LASSE#1,

LASSE#2, LAA#1, LAA#2.

Exploration drilling of LAARICH began on 2007. A well test has been conducted in 2012 but the

border of directors decides to shut down the well in order to increase its natural pressure. Laarich

oil field started producing in 2018.

I.7 Chapter Conclusion:

In this chapter, we have tried to explain briefly but precisely the main tools that we will use later

on in this report. A description of the oil field life cycle in the first paragraph linked with the

presentation of artificial lifting systems and in which cycle we have to them. Also, an explanation

of mathematical tools used in software calculation which are the well derivability and nodal

analysis giving us the two main curves to work with. And last but not least a brief description of

the oil concession that we are working on and the simulation software that we are using.

20


Chapter II. JET Pump Model Setup

This chapter presents the use of modelling software in the design of a producing oil well and the

modelling of the installed artificial lifting system as well as identifying the parameters responsible

for production optimization. As PROSPER calculations require building a natural flowing oil well

model before the design of any artificial lift system.

II.1 Well modelling without Jet Pump

II.1.1 Input Data

The developed model in this report is based upon an onshore well named LASE#2, in the

LAARICH field. Due to the long life of the reservoir, its pressure has dropped to a very low level

even with the ALS installed (JP) compared with its natural flowing state and as a result, production

may continue decreasing in the upcoming months.

The replacement of the ALS is eminent in order to achieve the optimization of the production. All

of the available data is separated into various categories and will be presented in this chapter. Each

data category will be modelled separately and subsequently all of them will be joint in a unified

model. When this model is tuned to real field data, PROSPER can confidently predict the well’s

performance under various scenarios. In this report, several scenarios based on various operating

conditions will carried out and an ESP will be designed. A detailed explanation of the role of each

data category will be analysed along with the way it is introduced to the software.

II.1.2 PVT data

The available PVT data is related to a direct flash (single stage separation) of the reservoir fluid

from reservoir conditions down to standard conditions done by CORE LAB Reservoir

optimization, Aberdeen U.K. According to its API gravity, the oil can be categorized as black oil.

II.1.3 Well Data

The well path is a typical vertical one. The wellbore diameter at the pay zone depth is 13024 ft.

The production casing diameter is 6” OD. The tubing ID diameter is 2.99”. As no measurements

of the pipelines roughness are available, the regular value of 0.0006” will be used. A subsurface

safety valve (SSSV) has been set as well as 5 production packers as shown in (Appendix 17a) and

(Appendix 17b) illustrating the well completion realiser by Weatherford in favour of ENI Tunisia.

Since the pipeline is passing through multiple reservoir up to the A8 layer, installed packers

21


stopping the production from other reservoirs and producing only from A8 layer. Also, the overall

heat transfer coefficient is estimated at 8.1 BTU/hr/ft2/F (PROSPER Data base).

II.1.4 Setting up the model in PROSPER

As mentioned at the beginning of this chapter, the main objective is to generate a mathematical

model, tuned against real field data that can describe as accurately as possible the well’s behaviour

under various future production scenarios. Each category of data will be modelled separately and

the developed sub-models will be joined to build a complete model capable of predicting the well's

performance.

The known procedure starts with the insertion of the basic information in the summary section.

After that, PVT data is entered and the appropriate fluid PVT correlations are selected. The system

is described in terms of downhole equipment. In the IPR section, the available data on reservoir

properties is used to generate the IPR curve for the current reservoir pressure. Then, a quality

control of the well test data is run in the VLP section to discard unrealistic measurements.

Subsequently, the correlation that best describes the flow in the tubing is matched against the

measured data. After completing all the above tasks, nodal analysis and investigation of future

production scenarios are finally possible.

II.1.4.1 Options summary

In this section, the main characteristics of the well are entered. Recall that it is a single branch

producing well, with a cased hole, no sand control, while production fluids travel through the

production tubing. The options selected are the following:

Table 1: Well Options Summary

Options Choice Fluid: Oil and Water PVT Method: Black Oil Separator: Single-Stage Emulsions: No Hydrates: Disable Warning Water Viscosity: Use Default Correlation Water Vapour: No Calculations Viscosity Model: Newtonian Fluid Steam Option: No Steam Calculations Flow Type: Tubing

22


Well Type: Producer Artificial Lift: None Predicting: Pressure and Temperature (on land) Temperature Model: Rough Approximation Range: Full System Completion: Cased Hole Sand Control: None Inflow Type: Single Branch Gas Coning: No Company: ENI – ETAP Field: Laarich Location: Tataouine Well: Laarich South East #2

The options are set so that emulsions (droplets of one liquid in another immiscible liquid) and

hydrates (ice-like solids that form when free water and natural gas combine at high pressure and

low temperature) are not taken into consideration. The reason is that they are mainly a matter of

concern in surface facilities (pipelines, manifolds, separators etc.) not the wellbore. Gas hydrates

may have an effect on flow assurance by causing hazardous problems. As far as the emulsions are

concerned, they lead to operational problems at the separating stage of oil and water and can

severely affect pumps. Since this is not the case under study, calculations based on emulsions and

hydrates will be omitted.

As far as the rheology of the fluids travelling through the wellbore is concerned, all phases are

treated as Newtonian ones as it is usually the case when modelling fluid flow in pipelines. It should

be noted that the rheological behaviour of the fluids is related to the prevailing pressure loss along

the tubing. To predict water viscosity, the default correlation implemented in PROSPER is used.

water viscosity at reservoir conditions is low almost always less than 1 cp. Although a pressure

corrected correlation is also available in PROSPER, it is not worth utilizing as water viscosity does

not greatly vary with pressure. This is due to the small amount of gas dissolved in the water and

its minor effect on viscosity. For the temperature calculations, the Rough Approximation model is

selected. It calculates the heat loss from the well to the surrounding formation with the use of a

heat transfer coefficient, the temperature difference between the fluids and the formation and the

average heat capacities. Note that the heat transfer coefficient is related to the easiness of heat

transfer flowing from the hot flowing fluids to the surroundings whereas the heat capacity of the

23


three phases determines the temperature reduction of the fluids due to the heat dissipation. The

geothermal gradient entry screen is used to input formation temperatures at measured depth points.

The formation temperature profile is then derived by interpolation between the input values. The

importance of a temperature modelling of the wells lies on the fact that temperature changes affect

pressure drop calculations. Generally, the (hot) reservoir fluids travel through the tubing towards

the (cool) surface. Inevitably, a heat loss will occur along the way from the liquid to the formation.

This temperature change will affect the average fluid properties, which in turn will alter the

pressure drop calculation (and hence the temperature change).

II.1.4.2 PVT Data Input

The surface PVT data given, such as Solution GOR, API gravity, gas gravity and water salinity

are used as input. This data provides a rough description of the thermodynamic behaviour of the

reservoir fluid. This is why it is only a rough description compared to a fully compositional model.

No gas impurities were reported. The next step is to match the available laboratory PVT measured

data with the black oil correlations. Two matching points are available (Well test data). The

properties at this point (GOR, oil viscosity) are also used as input.

Table 2: Fluid PVT Data

Options or Parameters Choice or Value Units

Reservoir Fluid: Water and Oil -

Separator: Single-Stage -

Solution GOR 65 (Sm3/Sm3)

Oil Gravity 41.482 (API)

Gas Gravity 0.832 (sp. gravity)

Water Salinity 12000 (ppm)

Mole Percent H2S 0 (percent)

Mole Percent CO2 0.9 (percent)

Mole Percent N2 0 (percent)

Pb, Rs, Bo Correlation Glaso -

Oil Viscosity Correlation Beal et al -

24


The next step is to match the available laboratory PVT measured data with the black oil

correlations. The properties at this point (GOR, oil viscosity) are also used as input.

Table 3: Fluid Laboratory Data

Temperature Pressure Bubble Point Gas Oil Ratio Oil FVF Oil Viscosity

(°C) (psia) (psia) (Sm3/Sm3) (m3/Sm3) (cp)

90 1200 2149 97.46 1.15 2.073

90 1800 2377 128.647 1.16 1.635

The reservoir temperature is already inserted previously and it is equal to 90°C. All the above data are

introduced in the PVT match data screen.

Figure 8: PVT Data before Matching

25


Figure 9: PVT Data After Matching

After entering the full set of available data, the software calculates the PVT properties mentioned

above and compares them to the experimental values which have been introduced in order for the

software to proceed to the matching process as shown in both (figure 8), (figure 9). PROSPER

performs a nonlinear regression which adjusts the correlations to best-fit the laboratory measured

PVT data (Test point). The non-linear regression technique applies a multiplier (Parameter 1) and

a shift (Parameter 2) to the correlations. The standard deviation is also displayed, which represents

the overall closeness of fit. The lower the standard deviation, the better the fit. The best overall

model is the one that has Parameter 1 closest to unity and Parameter 2 close to 0.

The reported values of the following PVT properties are used as match variables.

the main cause of pressure drop in the tubulars is the gravity and the corresponding hydrostatic term.

The density of gas and liquid phase at various pressures and temperatures, as well as the knowledge of

the proportion of the pipe occupied by liquid (holdup) are closely related with the PVT data. Thus, a

consistent PVT model is essential. Glaso’s correlation for Pb, oil FVF and solution GOR is selected

while Beggs’ correlation is selected to model the oil viscosity as the values of Parameters 1 and 2 lie

closer to 1 and 0 respectively compared to any other correlation. PVT data at every any pressure and

temperature can now be predicted with the adjusted black oil correlations.

26


II.1.4.3 Equipment Data Input

In this section of PROSPER, a detailed description of the well’s trajectory, surface and downhole

equipment, geothermal gradient and average heat capacities is given in the next figure,

II.1.4.3.1 Deviation Survey

As stated in the introduction of the available data, the well is a typical vertical one. That means that, it

is vertical down to the bottom hole. Deviation survey can configure horizontal wells which, at a certain

point, deviate with a certain degree.

Table 4: Well Deviation Survey

Measured Depth True Vertical depth Cumulative Displacement Angle [f t] [ft] [ft] [Degrees] 0 0 0 0

13024.9 13024.9 0 0

II.1.4.3.2 Surface Equipment

Are neglected in this study, since our system in comprised between the Christmas tree (Xmas Tree)

and the reservoir.

II.1.4.3.3 Downhole Equipment

Similarly, to the deviation survey, the description of the well’s equipment is necessary to calculate

the VLP of the well and the pressure and temperature gradients. As already discussed, the

calculations performed by the “Rough Approximation” model depends on the tubing ID. Tubing’s

ID and inside roughness are also used to estimate frictional pressure losses during production.

The Downhole Equipment screen enables the downhole completion data to be entered. The

production packers (5 packers at each restriction). The production tubing ends at 13024 ft. The

production casing runs from the surface and reaches bottomhole at 13024 ft. A summary and a

Sketch of Downhole Equipment are shown in (figure 10), (Figure 11)

27


Figure 10: Downhole Equipment Summary

Figure 11: Downhole Equipment Sketch

28


II.1.4.3.4 Geothermal gradient

The formation temperature at any depth can be computed by PROSPER by the means of the

geothermal gradient. A rough approximation of the temperature profile can be achieved by

introducing the known values of temperature at the surface and at the reservoir. The depth can be

introduced as a measured depth or a true vertical one. PROSPER then interpolates linearly all

points given by the user and models the temperature distribution of the formation in the various

depths. Because of the linear interpolation, at least two data points must be introduced. The

geothermal gradient and overall heat transfer coefficient are also introduced in this section and

take part in the produced fluids’ temperature prediction calculations, as explained in the former

paragraphs of this chapter.

Table 5: Well Geothermal Gradient

Formation Measured Depth Formation Temperature

[ft] [°C]

0 40

13024.9 90

II.1.4.3.5 Average heat capacities

The average heat capacities of water, oil and gas are used in the “Rough Approximation”

temperature model to calculate the dissipated heat when the fluid changes temperature. A good

approximation can be given by using the default values of Cp of oil, water and gas. However, it

should be noted that, Cp for oil and gas is not a constant value since their composition changes

and thus their properties change along depth.

Table 6: Fluid Average Heat Capacities

Properties Values Units

Cp Oil 0.53 (BTU/lb/F)

Cp Gas 0.51 (BTU/lb/F)

Cp Water 1 (BTU/lb/F)

II.1.4.4 IPR Data Input

This section defines the Reservoir Inflow Performance curve. Calculating an IPR curve results in

a relationship between the bottomhole pressure and the flow rate passing in the well. In this case

29


the “Vogel” model is used. The Vogel’s model applies by the time when the flowing pressure at

the bottom node (Pwf) becomes equal to the bubble point and hydrocarbon two phase flow takes

place. The IPR curve derivation and its role on Nodal analysis were well-discussed in previous

sections. The main screen of the IPR section is given in (figure 12).

Table 7: IPR Data Input

Options or Parameters Choice or Value UNIT

Reservoir Model Vogel -

Relative Permeability No -

Reservoir Pressure 5391 (psia)

Reservoir Temperature 90 (°C)

Water Cut 5 (percent)

Total GOR 65 (Sm3/Sm3)

Formation PI 1.24 (STB/day/psi)

Absolute Open Flow (AOF) 5478.5 (STB/day)

Test Rate 1038 (STB/day)

Test Bottom Hole Pressure 4551 (psia)

Figure 12: IPR data input main screen

30


In (figure 13), we are plotting the IPR curve:

Figure 13: IPR Curve

II.1.4.5 IPR/VLP Matching

Figure 14: IPR/VLP curve intersection (State zero)

31


The final step of the well set up is the IPR/VLP matching section. Since the VLP is now matched

and trusted, it must be examined whether the reported liquid rate at the surface is similar to the

well test production rate during its natural flow phase. the intersection between the IPR and the

VLP curve gives us the state zero data and giving us the production boundaries (Reservoir pressure

and production rate).

The calculations indicate a liquid rate of 2073.7 STB/day (329.7 m3/day), that is significantly

greater than the one reported by the latest well test which will be included later on in the JET Pump

performance. As far as the reservoir pressure is concerned, during well testing, the measurement

of the average reservoir pressure is achieved by closing the choke on the surface and stopping

production for a period of time. Actual reservoir pressure, though, may take several days to

balance. As a result, field engineers use extrapolation methods to predict the static pressure, which

may contain a certain amount of error.

This is the reason why; these operating conditions cannot be used to extract safe conclusions about

which parameter is more appropriate to be altered. The investigation must be done using operating

conditions where the two curves are rather complementary. This could correspond to lower a water

cut level or when the production is assisted by some type of artificial lift. For this reason, sensitivity

analysis for both cases was decided to be applied. Three different cases were considered: For each

adjusted parameter, (a) liquid rates for various water cut levels, (b) liquid rates for various GOR

values. In other words, an attempt was made to capture the difference in the IPR curve for certain

operating conditions, and in the meantime, the same VLP would intersect these IPR curves. For a

fixed top node pressure, the VLP curve is not affected. The VLP curves for both situations will

remain practically the same because changes occur only in the reservoir, so only the IPR curves

will be affected. If any significant difference in the liquid rate is reported, two different production

scenarios must be considered, as this would indicate that the inflow performance is affected in a

different manner by either of the two adjusted parameters. The results of the above-mentioned

process are given in detail in the next paragraphs.

II.2 Well modelling with Jet Pump

II.2.1 Jet Pump Options Summary

32


Table 8: JET Pump Data Entry

Parameters Values Units

Pump Depth (Measured): 6991 (ft) Maximum OD: 6 (inches) Surface Injection Rate: 1800 (m3/day) Surface Injection Pressure: 2550 (psia) Nozzle Loss Coefficient: 0.15 - Suction Loss Coefficient: 0 - Throat Loss Coefficient: 0 - Diffuser Loss Coefficient: 0 -

The selected equipment is JET PUMP - Nozzle (5) Throat (4) An 0.009 At 0.043 R 0.210 as

shown in the Appendices chapter (Appendix 18a) and (Appendix 18b).

II.2.2 Sensitivity analysis

Here comes the true utility and unicity of Prosper Petroleum Software, because of, and besides

well modelling and completion design, prosper proposes the study of different production

scenarios in order to define the factor or factors effecting the oil flow rate and production statistics.

In the sensitivity analysis, the user can study, case by case, the key factor or factors that needs to

be optimized and other factors which have no effect on the production rate.

In the calculation tab, we can utilize a 3-variable system calculation or 4-variable system

calculation at the same time (ALIYEV, 2013).

II.2.2.1 Sensitivity analysis on various water cuts:

Table 9: Sensitivity Analysis on Various Water Cuts


Water Cut 2 7.75 13.5 19.25 25 (percent)

Liquid Rate: 102.2 98.6 94.9 91.2 86.2 (m3/day)

Oil Rate: 100.2 90.9 82.1 73.6 64.6 (m3/day)

Water Rate: 2 7.6 12.8 17.6 21.5 (m3/day)

Gas Rate: 0.23 0.20 0.18 0.16 0.14 (MMscf/day)

Solution Node Pressure: 4870 4889 4908 4926 4952 (psia)

33


dP Friction: 769 764 758 753 747 (psi)

dP Gravity: 4670 4695 4720 4745 4779 (psi)

Pump Intake Pressure: 3163 3161 3159 3157 3154 (psia)

Pump Discharge Pressure: 3912 3912 3911 3910 3908 (psia)

Average Rate Through Pump:

707.5 679.1 650.9 622.7 585.8 (RB/day)

Pump Head Generated: 2147 2124 2101 2078 2057 (ft)

Pump Power Requirement:

849 859 870 881 892 (hp)

Pump Efficiency: 2.96 2.84 2.73 2.61 2.46 (percent)

Wellhead Gas Viscosity: 0.011077 0.011086 0.0111 0.01105 0.01 (centipoise)

Wellhead Pressure: 180 180 180 180 180 (psia)

Wellhead Temperature: 43.07 43.15 43.21 43.26 43.24 (° C)

First Node Gas Density: 0.73652 0.73584 0.73515 0.73876 0.73829 (lb/ft3)

First Node Liquid Viscosity:

1.1965 1.161 1.1259 0.99374 0.96986 (centipoise)

First Node Gas Viscosity: 0.011077 0.011086 0.0111 0.01105 0.01105 (centipoise)

First Node Pressure: 180 180 180 180 180 (psia)

First Node Temperature: 43.07 43.15 43.21 43.26 43.24 (° C)

Figure 15: Water Cut Curve

34


The Sensitivity Runs on Various water cuts scenarios shows that manipulating the value of water

cuts (2, 7.75, 13.5, 19.25, 25 %) has no real effect on oil flow rates. Since the intersection points

between the IPR and VLP curves show no difference what so ever between the different values of

water cuts. In the next paragraph, we will try a coupled scenario between water cuts and GOR.

II.2.2.2 Sensitivity analysis on various water cuts and GOR values:

Figure 16: Water Cuts/ GOR curve

The Water Cuts/GOR Curve shows that, similarly to the previous study has no effect on the oil

flow rate shown more clearly in the above figure (figure 16). Since the nature of our oil well, these

factors are irrelevant to the optimisations study.

As predicted, and as in most cases all around the world, the reservoir pressure is the only key factor

in production optimization since we can clearly notice in the negligible variation in liquid rates

form nearly all the Water Cut/ GOR values (Table 10).

Table 10: Sensitivity Analysis on various Water Cuts and GOR values


Water Cut 2 7.75 13.5 19.25 25 (percent)

Gas Oil Ratio 30 40 70 50 70 (Sm3/Sm3)

Liquid Rate: 92.9 91.8 96.3 87.3 87.5 (m3/day)

Oil Rate: 91.1 84.6 83.3 70.5 65.6 (m3/day)

35


Water Rate: 1.9 7.1 13 16.8 21.9 (m3/day)

Gas Rate: 0.096982 0.12019 0.20705 0.12511 0.1631 (MMscf/day)

Solution Node Pressure: 4917.97 4923.93 4900.65 4946.64 4945.51 (psia)

dP Friction: 754.23 751.26 761.97 745.96 749.84 (psi)

dP Gravity: 4728.81 4740.11 4710.14 4771.62 4769.77 (psi)

Pump Intake Pressure: 3180.08 3172.85 3157.16 3162.99 3152.33 (psia) Pump Discharge Pressure: 3925.88 3920.97 3909.4 3914.62 3907.16 (psia)

Average Rate: 606 606.8 666.2 583.1 599.3 (RB/day)

Pump Head Generated: 2096.6 2087.2 2109.4 2057.9 2064.5 (ft)

Pump Required Power 865.61 872.23 867.81 888.81 889.71 (hp)

Pump Efficiency: 2.548 2.552 2.795 2.453 2.519 (percent)

Wellhead Pressure: 180 180 180 180 180 (psia)

Wellhead Temperature: 42.69 42.86 43.27 43.09 43.3 (°C)

First Node Pressure: 180 180 180 180 180 (psia)

First Node Temperature: 42.69 42.86 43.27 43.09 43.3 (°C)

II.2.2.3 Sensitivity analysis on various pressure values:

The variation of reservoir pressure gives various liquid rates. As shown in (Table 11), we present

a summary comparing the different reservoir pressures and production rates.

Table 11: Sensitivity Analysis on various pressure values

Reservoir Pressure (psia) Liquid Rate (m3/day) Oil Rate (m3/day) Gas Rate (MMscf/day)

4925 11.8 11.8 0.025843

5350 51.2 48.7 0.11227

5775 90.4 85.9 0.19817

6200 129.4 123.0 0.28368

36


Figure 17: Sensitivity Analysis Results

The only obstacle facing the increasing of reservoir pressure with a Jet Pump is the danger of pump

cavitation as shown in (figure 18). This factor puts at risk the hole production operation because it

presents the possibility of destroying the formation, thus, the impossibility of recovering the

remaining quantities of oil. Multiple fractures appear in the reservoir walls resulting the escape of

oil back to the earth layers.

Figure 18: Jet Pump Boundaries

37


II.3 Chapter conclusion:

Here, we have tried through the data gathering from ETAP data base and the available documents,

to introduce as precise as we can, the information used in the model building to avoid any

calculation errors. It is now obvious that the installed artificial lifting system is no more able to

produce an economical flow rate due to its limited capacities and over-charged performance not

to mechanical nor electrical troubles with the mechanism. Running various scenarios on various

operating parameters provided us with the conclusion that only pressure is the key factor of

production optimization thus the need to replace the installed artificial lifting system.

38


Chapter III. ESP Model Setup

This chapter it is dedicated to the optimization of oil production by choosing the wise and

appropriate alternative and manipulating various parameters. Also, a cost estimation is provided

in order to evaluate the expenses and expected gains.

III.1 Artificial Lift Selection Criteria

III.1.1 Artificial lift system standards

Different factors could influence on the selection of the suitable artificial lift type for particular

well or group of wells. These factors could be classified in three classifications; the surface

considerations and the operating operations, well and reservoir considerations, and artificial lift

operating characteristics (Jahn, et al., 1998).

The following tables present a total view of the main types of factors:

Table 12: Surface considerations

Consideration Commentary

Flow rates Flow rates are governed by the back pressure of equipment as well as wellhead pressure

Flowline size and length

The length and the diameter of the flowline determine the WHP requirements and effect overall performance of the production system.

Contaminants The scale, paraffin and salt could affect the production.

Power sources Electricity of natural gas must be available

Field Location Consideration of multiple factors such as, surface access as well as well spacing, noise limits and safety and environmental conditions

Table 13: Operating considerations

Consideration Commentary

Long range recovery Plans

Field conditions may change overtime.

39


Pressure maintenance Operations

Water and gas injection may change the artificial lift requirements of the field.

Service support and personnel must be available

Some artificial lift systems require regular maintenance, monitoring and adjustment.

Table 14: ALS operating conditions

Operating System SRP JP ESP PCP Gas lift Typical operating depth (ft) 100 to 11000 5000 to

10000 1000 to 10000

2000 to 4500

5000 to 10000

Maximum operating depth (ft)

16000 15000 15000 6000 15000

Typical rate (bpd) 5 to 1500 100 to 4000

100 to 30000

5 to 2200 100 to 10000

Therefore, economic parameters such as initial capital expenses (CAPEX), monthly operating

expenses (OPEX) (which we will involve in the last chapter), Life of the installed equipment,

supplement of equipment (spray parts) and workover costs for each artificial lift system can

influence the artificial lift selection criteria. The initial capital expenses play important role in

installation of required AL types. But monthly OPEX are more interesting than initial CAPEX

through the life cycle of the well. The figure below estimates that the CAPEX investment contains

only 1% from the total value of AL installation, although OPEX can reach up to 6%. Therefore, it

is valuable to decide upon choosing the installation of the reliable equipment which are the most

suitable assuring the reduction of operating costs. Work overs costs are dependent on location of

operating field, the AL method and the service company contract terms (Hollund, 2010).

III.1.2 Artificial lift system choice

After taking in consideration different operating parameters and boundaries opposed by the

artificial lifting standards and selection criteria and protocols, and compared with the actual

available condition of LSE#2 well, we have decided the following:

SRP: optimal use designation for low volume production Eliminated

Gas Lift: absence of gas flow Eliminated

PCP: optimal use designation for low depth Eliminated

40


ESP: Best choice since JP is already installed and not performing as required due to over-charge.

III.2 Well modelling with ESP

Figure 19: Higher Reservoir Pressures with ESP

After running various scenarios, which we will summarize in the next table, the ESP ‘s

performance resultants were higher than the JET pump without any risk of cavitation and

maintaining the same well head pressure and avoid the danger of formation fracture.

Table 15: Recapitulative Table: Reservoir Pressure/Production Rate (ESP)

Reservoir Pressure

(psia)

Liquid Rate (m3/day) Oil Rate (m3/day) Gas Rate (MMscf/day)

5000 161.7 153.6 0.35449

5500 194.2 184.5 0.42565

6000 226.8 215.5 0.49717

6500 260.0 247.0 0.56997

7000 293.2 278.6 0.64274

41


Starting from a 6000 psia pressure value, the JET pump in endangered since it reaches its

functioning limits. It is obvious that in order to obtain an economically profitable flow rate

covering all of the expenses, the ESP must be installed because even at the same reservoir

pressure value, the ESP produces far more than the JET Pump. And as we explained previously,

the ESP’s reputation is common within the last stages of the oil field cycle.

Figure 20: ESP calculations with no risk of cavitation

As shown in the above table (Table 15) and (figure 20), the ESP can produce far higher than the

JET Pump, offering wide production rate options that the petroleum production engineer can

choose from.

Table 16: ESP Data


Pump Depth (Measured): 2170 (m)

Operating Frequency: 50 (Hz)

Maximum Pump OD: 5 (inches)

Length of Cable: 2180 (m)

Gas Separator Efficiency: 0 (percent)

42


Number of Stages: 469 Voltage @ Surface: 1978.82 (Volts)

Pump Wear Factor: 0.5 (fraction) In addition of the artificial lift selection criteria and the production rate selection by the petroleum

production engineer. A wise decision must be taken to chose the rest of parameters that define the

ESP Model. We tried at this stage to respect the production casing and tubing sizes, as well as an

economic power& utilities consumption offering nearly the same range or production rates.

III.3 Economical Evaluation

The aim of this profitable study is to ensure that maximum long-term economic benefit will

be gained by implementing the above selected artificial lift method,

• It permits to know, if the project is profitable or not, that’s a capital making-tool for

investment decision.

• It permits to make an economical calculation which is the confrontation between

immediate decision to investigate and the expectation of future revenues.

The economical calculations are based on:

• CAPEX (including abandonment cost) investment and OPEX (operating costs).

• Economical hypothesizes: Oil prices, Inflation.

• Contractual hypothesis: Contract type, Cost-Oil, Profit-Oil, Royalty, Taxes.

III.3.1 CAPEX

These provided values were presented by examining different financial reports on other oil

concessions in Tunisia and operated by ETAP and with the help and expertise of our industrial

supervisor, we have these updated equipment prices and services up until July 2018:

Pump & Cable Procurement: 1’700’000$

Installation: 400’000$

One-month Workover/Rig: 12’000$ / day

Transportation and Tubing: 120’000$

Five-Day Company Service: 12’000$ / day

Capex Total: 2’640’000 $

43


Table 17: CAPEX Expenses

Equipment Prices Units

Pump & Cable Procurement 1.7 M$

Installation 400 K$

One-month Workover/Rig 360 K$

Transportation and Tubing 120 K$

Five-Day Company Service 60 K$

TOTAL CAPEX 2.64 M$

III.3.2 OPEX

As mention above, these are the updated equipment prices and services up until July 2018

Maintenance and Replacements (Valves and components…): 350’000$

TRAPSA: 500’000$

Operating Staff: 50’000$ / day

Power & Utilities: 150’000$

Chemical Products: 50’000$

• Reserve Estimation:

In order to calculate expenses during time, we have to use the Oil in place OOIP formula and asses

the reserves left in the reservoir multiped by the recoverable factor (usually 30%)

OOIP = �V�� !"#

$ = % ∗ ℎ ∗ '"# ∗ φ !"#

Where: OOIP: Oil in Place [m3]

A: The area of reservoir [m2]

h: The height of pay zone [m]

Soi: Connate water salination [%]

φ: Porosity [%]

Boi: Formation volume factor [m3/m3] = 1.243 (PROSPER Data base)

44


Table 18: Reserves Estimation

Zone A h φ Soi OOIP

B_2 700000 0,45 0,111 0,942 32937,03

B_2-1 700000 0,3 0,143 0,949 28498,47

A_1-a 700000 1,05 0,111 0,951 77587,335

A_5-1 700000 2,7 0,145 0,88 241164

A8 700000 3,3 0,193 0,92 410163,6

A8b 700000 0,45 0,147 0,924 42785,82

Reserves = ∑OOIP = 670262.46 m3

Recoverable Oil = OOIP * 30%

Recoverable Oil = 201078.74 m3 (equals 1264747.22 bbls)

The next table summarizes the recovered quantities between well test and periodic production as

well as the remaining volumes to extract

Table 19: Recovered and Remaining Volumes

Volume Type Values Units

Total Reserve 201078.74 m3

Recovered Volume 15178 m3

Remaining Volume 185900,7 m3

With A daily production of 1500 bbls (238.4 m3), we need a time period of 780 days before

decommissioning. Through 2 years and one month, an annual maintenance break is required, thus

two times Shut-down for our ESP and afterwards the Shut-down Expenses will later be added to

the OPEX as they are time variable expenses. Note that these figures are able to change over time

since they are directly related to international business and financial markets as well geopolitical

conflicts.

Shut- down Expenses:

10 days workover: 235’000$ / day

30 days waiting for mobilization of rig

2 days electricity failure

All of these prices will be later combined into one index of a 32 days operating staff expenses:

50000$ / day added to the total OPEX expenses.

45


Total operating staff expenses: 3’950’000$

Table 20: OPEX Expenses

Equipment Price Units

Maintenance and Replacements 350 K$

TRAPSA 500 K$

Operating Staff 39 M$

Power & Utilities 150 K$

Chemical Products 50 K$

Shut-Down Expenses 3.9 M$

TOTAL OPEX 4.989 M$

We will now calculate the profitability of our project:

Barrel price: $ 75.

Gross income is calculated for total reserves = 94’856’041.5 $

By definition: Net income = Gross income – Taxes (50 %)

Taxation = 43582020.75 $

The results of the estimate of future revenues for the property LASE#2 can be shown in the table

below:

Table 21: Economical Balance

Financial index Value Units

Gross Income 94.8560415 M$

Expenses (CAPEX + OPEX) 7.629 M$

Taxation 43.58202075 M$

NET Income 51.27402075 M$

III.4 Chapter conclusion:

In this final chapter, we have located the optimal artificial lifting system and the most

appropriate in terms of required flow production rate as well as equipment commissioning and

procurement. The Electrical submergible pump will best suit the conditions of Laarich reservoir

as the most profitable solution to the still decreasing production rate provided by the Jet pump.

46


General Conclusion

Laarich South East #2 oil well witnessed a serious decline of production rate far from its initial

well performance. That’s why ETAP is investigating alternative solutions for upgrading the current

artificial lift system.

During this project, we modelled the oil well with two different artificial lifting systems: Jet Pump

and Electrical Submersible Pump (ESP) using production and system performance analysis software

(PROSPER). We performed a cost estimation study for the proposed solution based on ESP use.

After the insertion of the required parameters and the oil properties, the well model was build using

PROSPER.

We proceeded with the matching to the real proprieties of both the oil well and the studied fluid

choosing the adequate correlations available in PROSPER’s data base. A sensitivity analysis has

been conducted using the same software to identify the key factor allowing to increase the

production flow rates by investigating several scenarios for water cuts, Gas Oil Ratio (GOR) as

well as the reservoir pressure. It has been found that reservoir pressure is the main factor affecting

the production rates.

After that, we have been able to locate the adequate pressure and configure the optimal parameters

of the ESP and its accessories. At last, we performed an economical evaluation to demonstrate the

benefits of changing the already installed artificial lift system considering the time factor and the

need of the production company to decommission the oil well after a long period of low production

paste.

This work could be extended to the remaining wells of the field in order to choose the most efficient

artificial lift systems. A similar economical evaluation could be achieved in order to demonstrate

the need for upgrading the artificial lift systems.

47


Bibliography

Akthar , A. et al., 2014. Optimization, diagnostics and troubleshooting of gas lift wells, Master Thesis,

Indian School of Mines: s.n.

ALIYEV, E., 2013. Development of expert system for artificial lift selection, Master thesis, Middle east

technical university: s.n.

Danesh, A., 1998. PVT and Phase Behaviour of Petroleum Reservoir Fluids. 2nd Edition ed.

s.l.:ELSEVIER.

Fares, M., 2016. Artificial Lift Optimization Study & Recommendations for Ezzaouia Field, Master

Thesis, University of Tunis EL manar: s.n.

Hernández, A., 2016. Fundamentals of Gas Lift Engineering, Well Design and Troubleshooting. 1sr

Edition ed. s.l.:Gulf Professional Publishing.

Hollund, B. S., 2010. Artificial Lift – Electrical Submerged Pump, best practice and future

demandswithin subsea applications, Master Thesis, University of Stanvanger: s.n.

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Conference .

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Edition ed. s.l.:ELSEVIER.

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s.l.:ELSEVIER.

P.E., T. P., 2017. Artificial Lift. [Online]

Available at: http://petrowiki.org/Artificial_lift

Petroleum, P., 2012. Prosper Toturial, Texas: s.n.

Takacs, G., 2018. Electrical Submersible Pumps Manual, Design, Operations, and Maintenance. 2nd ed.

s.l.:ELSEVIER.

Tetoros, I. E., 2015. Design of a continuous gas lift system to initiate production in a dead well , Master

Thesis, Technical University of Crete: s.n.

V. Nickens, H., R. W, M. & F. Lea, J., 2003. Gas Well Deliquification. 1st Edition ed. s.l.:ELSEVIER.

Woods, J. D. & James F. Lea, 2017. What’s new in artificial lift? Part 1. World Oil Magazine, Volume

Vol 238 No. 5, pp. 2-5.

Yabada, S., 2017. IPR Outflow Performance, s.l.: Scribd web site.

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Appendices

Appendix 1: System Summary

Appendix 2: PVT Data Input.

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Appendix 3: PVT Laboratory Data

Appendix 4: PVT Data Matching Parameters and Models

50


Appendix 5: Equipment Data Input Main Screen

Appendix 7: Deviation Survey Input Data

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Appendix 8: Downhole Equipment Input Data

Appendix 9: Geothermal Gradient Input Data

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Appendix 10: Average Heat Input Data

Appendix 11: Jet Pump Specifications

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Appendix 12: Sensitivity runs on various water cuts

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Appendix 13: Sensitivity runs on various water cuts and GOR values

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Appendix 14: Sensitivity Analysis on various pressure values

Appendix 15: ESP specifications

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Appendix 16: LARRICH SE#2 PVT Data

57


Appendix 17a: LARRICH SE#2 Well Completion

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Appendix 17b: LARRICH SE#2 Well Completion

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Appendix 18a: Jet Pump Constructor Data

60


Appendix 18b: Jet Pump Constructor Data

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