report_25.07.2012_rev1

4 JUNE-27 JULY (2012)

SUMMER INTERNSHIP REPORT ON

“FLOW ASSURANCE FOR DEEPWATER FIELD DEVELOPMENT”

CERTIFICATE

This is to certify that the Summer Internship on “FLOW ASSURANCE FOR

DEEPWATER FIELD DEVELOPMENT” submitted towards partial fulfillment of the

requirements for the award of the Bachelor in Technology (B.tech) in Applied

Petroleum Engineering and submitted as an authentic record carried out under the

supervision of Mr. Naresh Narang (GM {HOD}) E&P Department and Mr. B Ghosh

(DGM) E&P Department Reliance Industries Limited, Reliance Corporate Park

(RCP) Ghansoli, Navi Mumbai, Maharashtra.

The work is entirely original and authentic.

All the information provided is true to the best of my knowledge.

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Avinash Chandra Lohumi

University of Petroleum and Energy Studies

SAP ID : 500007539

Roll No: R010209017

B Tech (Applied Petroleum Engineering)

III Year

Mr. Naresh Narang

Senior Vice President [HOD E&P])

Reliance Industries Limited,

Reliance Corporate Park, Ghansoli

Navi Mumbai, Maharashtra

Mr. B. Ghosh

(General Manager, (E&P)

Reliance Industries Limited,

Reliance Corporate Park, Ghansoli

Navi Mumbai, Maharashtra

ACKNOWLEDGEMENT

I would like to express my deep sense of gratitude to my respected mentors, Mr.

Naresh Narang and Mr. B Ghosh for their timely guidance, valuable support and

encouragement at every step in preparing this report and successfully completing it.

They are a great source of inspiration and motivation and helped me to get all the

knowledge and skills required for this project. My sincere thanks also goes towards

my Co Mentor Mr. D.V Sundar Rao for his valuable support at every step.

I would like to thank Reliance Industries Limited for providing me with a wonderful

opportunity to observe to at close quarters, the real world of industries.

Without the co-operation of the above persons this work certainly would not have

been as good as it is now.

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FLOW ASSURANCE

FOR DEEPWATER FIELD DEVELOPMENT

REPORT

TABLE OF CONTENTS

Certificate……………………………………………………………………………………..2

Acknowledgement……………………………………………………………………………3

Executive summary…………………………………………………………….…………….6

Abbreviations…………………………………………………………………………………7

1. Introduction to Flow Assurance………………………………………………………..8

2. Case Study………………………………………………………………………………10

3. Field Layout……………………………………………………………………….…….11

4. Basis and Assumptions……………………………………………..………………...13

a) Composition…………………………………………………………………………...12b) Reservoir pressure ………………………………………………………..………….13c) Production Profile……………………………………………………………………..14

I. Tubing Head Pressures………………………………………….………….14II. Production rates……………………………………………………………..14

III. Water Production Rates…………………………………………………….15

d) Simulation Softwares……………………………………………………………...…16e) Hydrate Inhibitor…………………………………………………………….……..…17f) Erosion Velocity limits…………………………………………………………...….18g) Pipeline Details…………………………………………………………………….…19h) Host Facility requirements………………………………………………………..…20 i) Heat Transfer data………………………………………………………………..….21j) Sales gas specification………………………………………………………………22

3. Concept Selection………………………………………………………………….......…234. Thermo- Hydraulic studies………………………………………………………….…....24

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I. Field Architecture………………………………………………………………...…….25II. Infield Pipeline sizing…………………………………………………………….....…26

III. Trunkline sizing…………………………………………………………………..…….31IV. Selection of trunkline configuration………………………………………………....33V. Inhibitor requirements…………………………………………………………....……34

VI. Arrival pressures at Host facility- Forward approach…………………………...…36VII. Arrival pressure at Host facility-Backward approach…………………………...…42

VIII. Timing of compression and compression power requirements………………..…44

5. Facilities required for processing hydrocarbon fluids………………..………….…45

APPENDIX 1………………………………………………………………………….………….47

APPENDIX 2……………………………………………………………………………………..51

APPENDIX 3……………………………………………………………………………………..58

APPENDIX 4……………………………………………………………………………………..59

REFERENCES…………………………………………………………………………………...62

GLOSSARY………………………………………………………………………………………63

LIST OF FIGURES

Figure 1-Field Schematic……………………………………………………………………..11

Figure 2- Block Diagram of condensate and gas processing at OT…….……………41

LIST OF GRAPHS

Graph 4.1.1-Heat transfer data…………………………………………………..……………21

Graph 4.2.1-Infield pipeline sizing-Well A………………………………………………….26

Graph 4.2.2-Infield pipeline sizing-Well B………………………………………………….27

Graph 4.2.3-Infield pipeline sizing-Well C………………………………………………….28

Graph 4.2.4-Infield pipeline sizing-Well D………………………………………………….29

Graph 4.2.5-Infield pipeline sizing-Well F……………………………………..…………..30

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Graph 4.3.1-Trunkline sizing (Single)…………………………………………………………32

Graph 4.3.2- Trunkline sizing (Dual)………..…………………………………………………33

Graph 4.5.1- Inhibitor requirement………………………………………………………….....35

Graph 4.6.1- Arrival pressure-Forward approach – Dry gas……………...………………36

Graph 4.6.2- Arrival pressure-Forward approach – Dry gas (Year 0)……………………37



Graph 4.6.5- Arrival pressure-Forward approach – Gas condensate………….………..40

Graph 4.6.6- Arrival pressure-Forward approach – Gas condensate (Year 0)…………41



Graph 4.7.1- Arrival pressure-Backward approach – Dry gas…………………………….44

Graph 4.7.2- Arrival pressure-Backward approach –Gas condensate…………………..44

LIST OF TABLES

Table

Table 2.2 Composition……………………………………………………………………..….….13

Table 4.c-1 Production profile………………………………………………………….….……15

Table 4.c-2 Formation Water ………………………………………………………….………..16

Table 4.g-1 Pipeline details………………………………………………………….…………..20

Table 4.j-1 Sales gas specification……………..……………………………………………...23

Table 4.5.1 Inhibitor requirement (Dry gas)………………………………………………..…36

Table 4.5.1 Inhibitor requirement (Gas condensate)……………………………………..…36

Table 4.8.1 Timing of compressor and compression power requirement………………45

Table 4.8.1 Condensate production at OT…………………………………………………….45

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Executive Summary

This report describes the methodology or process that a flow assurance engineer

follows in developing a successful, cost effective subsea production system and its

operating philosophy by considering a case study.

During the course of this case study, various aspects for deepwater field

development were undertaken with respect to

Development of field architecture.

Steady state simulations to establish pressure drops

Establish operating envelopes.

Identify Flow Assurance issues and develop their prevention actions.

Facilities required for processing the reservoir fluids to sales specification.

At the end of this report, detailed description on Multiphase flow behavior, Nature of

reservoirs, Types of hydrates & inhibition mechanisms are discussed in the

Annexure.

Although not mentioned in this report, understanding of P&IDs of Subsea Structures

(like Manifolds, DWPLEM, XMT) and Control Structures (like SDA, SDU, UDH) along

with Cause and Effect matrix for Subsea Production System.

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Abbreviations

The following abbreviations are used within this report

BBL Barrels

MM Million (10^6)

OGPT Onshore gas processing terminal

MEG Mono ethylene glycol

SCFD Standard cubic feet per day

TEG Tri Ethylene Glycol

SCMD Standard cubic meter per day

FTHP Flowing tubing head pressure

SW Shallow Water

WD Water Depth

SDA Subsea Distribution Assembly

SDU Subsea Distribution Unit

UDH Umbilical Distribution Hub

DWPLEM Deepwater Pipeline End Manifold

XMT Christmas Tree

WT Wall Thickness

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1.0 Introduction

Why Flow Assurance?

Flow assurance refers to ensuring successful and economical flow

of hydrocarbon stream from reservoir to the point of sale. The term was coined

by Petrobras in the early 1990s in Portuguese as Garantia do

Escoamento (pt::Garantia do Escoamento), meaning literally “Guarantee of Flow”, or

Flow Assurance.

Concerns during production phase:

Pipeline or wellbore rupture from corrosion

Pipeline blockage by hydrates or wax

Severe slugging in riser destroys separator

Well can’t lift its liquids and dies

Separator flooded by liquids

Large pressure losses in pipelines cause flow rates to be lower than

should be

By adequately modeling and identifying the above mentioned issues during design

phase lies the challenge. Flow assurance is most critical task during deep water field

production because of the high pressures and low temperature (~2 degree Celsius)

involved. The financial loss from production interruption or asset damage due to flow

assurance mishap can be astronomical.

How Flow Assurance works?

Flow assurance is extremely diverse, encompassing many discrete and specialized

subjects and bridging across the full gamut of engineering disciplines. By network

modeling ,transient and steady state multiphase simulation, flow assurance involves

effectively handling all aspects of production from the reservoir through to the plant

inlet by

I. Calculating mixture composition in pipeline

II. Calculating flowing temperature

III. Calculating flowing pressure

IV. Comparing the above to the conditions required for corrosion, hydrates,

wax, severe slugging, and liquid loading

V. Determining how these items change with depletion and with operating

conditions

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Steady state and transient simulations are based on models. The aim of modeling is

to describe mathematically

I. what has happened

II. what is happening

III. what will happen in a physical system

Modeling is a very cost effective way to

Enable safe operation

Optimize new and existing systems

Reduce downtime

Enable rigorous screening of various options in existing and potential

systems

Reduce uncertainty

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2.0 Case Study

For the purpose of flow assurance study, a deepwater field is taken up as a case

study. This field is located 50-60 km away from shore in water depths ranging from

1500-1600 meters. The main objective of this case study is to

I. Develop a field architecture

II. Sensitivity of reservoir fluid composition on facilities design

III. Steady state simulation to establish pressure drops.

IV. Identify Flow Assurance Issues/ Challenges & Solutions.

V. Establish operating envelope.

VI. Facilities required for processing the hydrocarbon fluids.

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2.1 Field Schematic

The following schematic shows the field location which is located 50-60 km from

shore. The field consists of 5 wells located in water depth varying from 1500 to 1600

meters.

Fig 2.1-Schematic Layout of the field

FIGURE 1Note: Land Fall Point is the interface between onshore and offshore.

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ONSHORE ( Land)

OFFSHORE (Subsea)

50-60 km

Schematic not drawn to scale

Located in 1500 – 1600 m WD

Land Fall Point

Well A

Well B

Well D

Well E

Well F

2.2 Composition

Generally reservoirs can be classified into four types:

I. Dry gas: Doesn’t form liquid phase and contains high proportion of methane.

II. Wet gas: Forming a liquid phase during production at surface conditions.

III. Gas Condensate: Forms a liquid phase in the reservoir during the depletion

process.

IV. Oil reservoir: An oil reservoir is an underground pool of liquid consisting of

hydrocarbons, sulphur, oxygen and nitrogen trapped within a geological

formation.

For detailed description of the reservoir types, refer to Appendix-2

In this case study, dry gas & gas condensate are considered and the composition is

given in the following table:

ParametersDry gas

Gas Condensate

Dry basis (mol %)

Nitrogen (N2) 0.64 0.55

Carbon Dioxide (C02) 0.19 0.76

Methane (CH4) 98.43 88.96

Ethane (C2) 0.13 4.8

Propane (C3) 0.06 2.22

Iso-Butane (i-C4) 0 0.44

n-butane (n-C4) 0 0.66

Iso-Pentane (i-C5) 0 0.33

n- Pentane (n-C5) 0 0.32

Cyclo Pentane (Cy-C5) 0 0.02

Hexane (C6) 0.07 0.48

n-heptane (n-C7) 0 0.37

n-Octane (n-C8) 0 0.1

n- Nonane (n-C9) 0 0.003

Other heaviers 0 Traces Table 2.2

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IV.0 Basis and assumptions

4.b Reservoir Pressures:

The reservoir pressures of the well are in the range of 240-250 bara. The wells are

assumed to be interconnected and have active aquifer. The maximum reservoir

temperature is 40oC

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4.c (I,II) Production Profile

The following table shows the well wise production profile:

YearFlow rate, MMSCMD FTHP, bara

Well A

Well B

Well D

Well E

Well F

Field Production

Well A

Well B

Well D

Well E

Well F

0 2 2 2 2 2 10 230 230 230 230 230

1 2 2 2 2 2 10 210 210 210 210 210

2 2 2 2 2 2 10 190 190 190 190 190

3 2 1.5 1.2 1.8 1 7.5 170 170 170 170 170

4 1 1.5 1.2 1.8 1 6.5 150 150 150 150 150

5 1 1.5 1 1.5 1 6 110 110 110 110 110

6 1 1.5 1 1.3 1 5.8 90 90 105 105 105

7 0.5 1 0.5 2 80 80 80

8 0.5 1 0.5 2 70 70 70

Table 4.c-1

As seen from the above table, the maximum well production is 2 MMSCMD & peak

production rate of field is 10 MMSCMD for two years and field life is 8 years.

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4.c (III) Formation water profile:

Since the field is of active aquifer, along with the gas production, water is also

expected to be produced. The water production is contributed in two forms,

Formation water and Saturated water. Formation water is produced as a liquid phase

and increases during the field life. Saturated water exists in vapour phase saturated

with the gas at reservoir conditions. The amount of water vapour in the gas phase

increases with increases in temperature and decrease in pressure. Following table

shows year wise formation water and saturation water production profile.

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Formation water production

Saturated waterproduction

bbl/MMSCF

0 0.35

1 0.38

2 0.4

3 0.43

4 0.45

5 0.58

6 0.63

7 0.68

8 0.7

Table 4.c-2

Note: Saturation water is calculated at given FTHP and at maximum reservoir temperature

As seen from the above table, as the life of the field progresses, formation water contribution towards the total water production increases.

4.d Simulation Software

INPLANT and PIPEPHASE simulation Software are used to carry out the steady

state flow assurance studies. Beggs and Brill Moody Co-relation is used for pressure

drop calculations.

PVT-Simulation software is used to generate the hydrate curves. HYSYS software is

used to calculate the fluid properties and compression power requirements.

For detailed description of the above softwares, refer to Appendix-3

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4.e Hydrate Inhibitor

Gas hydrates are crystalline ice- like solids formed from water and a range of lower

molecular weight molecules, typically methane, ethane, propane, hydrogen sulphide

and carbon dioxide. The structures of the crystals fall into the class of clathrates with

the water molecule forming hydrogen- bonded cage like structure which is stabilized

by “guest” Molecules located within the lattice.

The amount of inhibitor required to inhibit hydrate formation is calculated by Hammer

Schmidt Equation as given below

ΔT X 1.8 = K

MolWt * Kgof∈hibitorKgof water

WhereΔT: Change in temperature (*C)

K: Empirical constant (2335- 4000)

Mol Wt.: Molecular weight of the inhibitor.

The above equation can be used for Rich MEG concentration up to 60-70 %. For

Methanol, concentration up to 30%.

For detailed description of the Hydrate & Hydrate inhibitors, refer to Appendix-4

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4.f Erosion Velocity Limit:

The Erosion velocity is defined as the maximum allowable velocity within which the

fluid velocity of the multiphase mixture should be maintained.

API-RP 14E is used to calculate the erosion velocity by the following equation:

VE=¿ c

√ ρM¿

Where:

C: empirical constant

ρ: Mixture density in lb/ft3

Ve: ft/sec

For the purpose of this case study “c” value is chosen as 100

For detailed description on Erosion velocity, refer to Appendix 5

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4.g Pipeline Details:

Based on the gas composition, detailed in the section 2.2 X-65 grade is selected

(since it is a sweet gas).

Based on the maximum reservoir pressure, ASME 1500 class rated pipeline is

selected.

The following pipeline diameters are considered for sizing of flowlines (Wells to

manifold) and trunklines (manifold to OT):

Since the field is located in deeper waters, pipeline sizes are limited to 20”

considering the challenges for installation.

OD, inch WT, mm

6.625 11.1

8.625 14.3

10.75 15.9

12.75 15.9

14 19.1

16 19.1

18 19.1

20 25.4

Table 4.g-1

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4.f Host facility requirements

Minimum arrival pressure of 80 bara is considered to avoid onshore compression

and 40 bara is considered as the minimum pressure required for safe operation of

onshore compressors.

4 bar drop is considered across the processing facilities that is from Pressure

Reducing Station (PRS) to sales gas compressor station.

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4.i Heat Transfer Data

For the purpose of steady state thermo hydraulic simulations, Overall heat transfer

coefficient is considered. Since the infield and trunk line pipelines are located in

subsea, they are mostly covered with soil and the overall heat transfer coefficient is

in the range of 30 to 50 W/m2K (for non concrete coated pipelines), hence for the

purpose of this case study 50 W/m2K is chosen.

The seabed temperature at the well location is approximately 3oC,

Following graph shows the subsea ambient temperature profile from wellhead to the

land fall point:

0 200 400 600 800 1000 1200 1400 16000

2

4

6

8

10

12

14

16

18

Subsea Ambient Temperature Profile

W D, meters

Tem

pera

ture

, oC

Graph 4.i.1

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4.j Sales Gas Specification

The following table gives the typical sales gas specification to be met after

processing the gas

Characteristic Requirement

Max Water Content 80 kg/MMSCM (5lbs/MMSCF)

H2S Content < 4 ppm

Free Oxygen <0.2% (by volume)

Non Hydrocarbons <5% (by volume)

Hydrocarbon Dew point Maximum of 8oC @ 76 bar

Sales Gas Pressure 76 barg (max)

Temperature Maximum 55oC

Temperature Minimum 25oC

Wobbe Index 48.2 to 52.2 MJ/m3

QualityFree from dust, gum, gum forming

constituents.

Table 4.j-1

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3.0 Concept Selection

Development of gas/oil fields is broadly classified into one or combination of the

following options:

1. Subsea Completion + pipeline transport + full onshore plant.

2. Subsea completion + subsea processing+ pipeline transport +onshore

process plant.

3. Subsea completion + topside minimum process / minimum facilities + pipeline

transport + onshore process plant.

4. Subsea completion + topside full process + pipeline export.

5. Surface completion + topside minimum process / minimum facilities + pipeline

transport + onshore process plant.

6. Surface completion + topside full process + pipeline export.

Based on the location of the well depths (~ 1500 m WD), Option-5 & Option-6 are

eliminated. In view of high reservoir pressures (240 bara) and medium distance from

shore (50-60 km) which do not pose great technical challenge, Option-1 which is

Subsea Completion + pipeline transport + full onshore plant is considered as a

base concept.

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4.0 Thermo-hydraulic studies

Flow assurance issues such as hydrates, wax etc, pressure drop within system,

onset compression requirements are evaluated by thermo hydraulic analysis.

Sizing of pipelines is the first task to carried out during this study. Majority of

pipelines are sized by the use of primary design criteria

1. Minimum pressure drop

2. Minimum holdup

3. Maximum allowable velocity should be within erosion velocity

Usually the field has forecasted flowrates, including minimum and medium flowrates

for the early production stages. The flowrate reaches a maximum value, and it

subsequently decreases due to reservoir depletion. When the system is operating

with minimum flowrates, operational problems can occur due to the increment of the

total liquid content in the pipeline and the presence of terrain hydro-dynamic

slugging.

The pressure drop in the line is not always maximum at the highest flow rate and

maximum drop may occur at low flow rates if the pipeline is inclined due to elevation

losses at low flow rates. The pipeline sizing should be done in such a way that the

pressure drop during the length of the pipeline is minimum so that the natural

reservoir pressure is not wasted and transportation can be provided for a significant

period of time without the requirement of external medium (Compressors)

Simulations which assume that the pressures, flow rates, temperature and liquid

holdup in the pipelines are constant with time, the assumption is rarely true in

practice but line sizes calculated from Steady State models are highly adequate.

For more vigorous pipeline sizing, the simulations could be done using transient

simulations as transient simulations allow changes in parameters such as inlet flow

rates and outlet pressure as a function of time. If the pipeline is operating in slug flow

the line size calculated from the transient model might be different from the

calculated model of the Steady State simulator.

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4.1 Field Architecture

Based on the concepts identified in the previous section, Field architecture defines

how the wells are connected and transported to the host facility in the following

ways:

Manifold architecture

Loop architecture

Combination of loop and manifold architecture

For the purpose of this study, manifold architecture is selected, as this architecture

offers minimised holdup inventory and increased turndown ability.

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4.2 Infield Pipelines Sizing

Based on the criteria detailed in the section 4.0, each flowline (that is pipeline

between wellhead and manifold) is sized based on the maximum, minimum flowrate

detailed in the section 3.3. Variation of pressure drop and liquid holdup with Nominal

diameter for each well is shown in the following graphs

Well A to Manifold:

4 6 8 10 12 14 16 18 200

10

20

30

40

50

60

70

0.00

0.02

0.04

0.06

0.08

0.10

0.12

Flowline Sizing-Well A

Max gas rate - Pressure dropMin gas rate - Pressure dropMax gas rate - holdupMin gas rate - hold up

Nominal O.D, Inch

Pres

sure

dro

p, b

ar

Hold

up fr

actio

n

Graph 4.2.1

From the above graph, following observations are drawn:

As diameter increases, pressure drop sharply decreases till one point and

thereafter almost remains the same

pressure drop is in the range of 63.5-3 bar

Holdup gradually increases with increase in line diameter.

Holdups are in the range of 0.048-0.011 which does not pose operational

constraint.

Based on the above observation and criteria listed in the section 4.0, 10” Nominal

diameter is selected for the flowline between well A to manifold.

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Well B to Manifold:

4 6 8 10 12 14 16 180

10

20

30

40

50

60

70

80

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09Flow line sizing: Well B

Max gas rate-pressure dropMin Gas Rate-Pressure DropMax gas rate- holdupMin gas flow rate- holdup

O.D , inches

Pres

sure

dro

p (b

ar)

Hol

dup

Frac

tion

Graph 4.2.2


As diameter increases pressure drop sharply decreases till one point and


Pressure drop is in the range of 68-5 bar


Holdups are in the range of 0.015-0.083 which does not pose operational

constraint.


diameter is selected for the flowline between well B to manifold.

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Well D to Manifold

4 6 8 10 12 14 16 180

5

10

15

20

25

30

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14Flowline Sizing-Well D

Max gas rate - Pressure dropMin gas rate - Pressure dropMax gas rate - holdupMin gas rate - hold up

Nominal O.D, Inch

Pres

sure

dro

p, b

ar

HOLD

UP F

RACT

ION

Graph 4.2.3




Minimum pressure drop is in the range of 27-4 bar


Maximum Holdups are in the range of 0.101-0.13 which does not pose

operational constraint.


diameter is selected for the flowline between well D to manifold.

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Well E to Manifold

4 6 8 10 12 14 16 180

10

20

30

40

50

60

70

80

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

Flow line sizing: Well E

Max gas rate-pressure dropMin Gas Rate-Pressure DropMax gas rate- holdupMin gas flow rate- holdup

O.D , inches

pres

sure

dro

p (B

ar)

Hold

up F

racti

on

Graph 4.2.4









diameter is selected for the flowline between well E to manifold.

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Well F to Manifold

4 6 8 10 12 14 16 180

5

10

15

20

25

30

35

40

0.00

0.02

0.04

0.06

0.08

0.10

0.12Flowline Sizing-Well F

Max gas rate - Pressure drop

Min gas rate - Pressure drop

Max gas rate - holdup

Min gas rate - hold up

Nominal O.D, Inch

Pres

sure

dro

p, b

ar

HOLD

UP F

RACT

ION

Graph 4.2.5









diameter is selected for the flowline between well F to manifold.

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4.3 Trunkline sizing

Trunklines are defined as the pipelines that transport the total production from

gathering systems (manifold) to the host facility.

Generally depending on the field architecture, length of trunk line, reservoir

composition and production rates, the trunk line configuration can be divided into two

categories

Single Trunk line configuration

Multiple trunk line configuration ( In this case study, dual line configuration is

chosen)

Sizing for single trunkline configuration

14 16 18 200

10

20

30

40

50

60

70

80

0.000

0.005

0.010

0.015

0.020

0.025

0.030

0.035

0.040

0.045Single Trunkline Configuration

Max gas vol- pressure drop

Nominal Diameter,inches

Pres

sure

Dro

p,ba

ra

Hold

up -

frac

tion

Graph 4.3.1


For 14” ND, flow cannot occur due to high frictional loss. As diameter

increases, pressure drop sharply decreases till one point and thereafter

almost remains the same

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Based on the above observations, 20” trunkline is selected as a optimum pipeline

size in single trunkline configuration.

Sizing for Dual trunkline configuration

14 16 18 2010

15

20

25

30

35

40

45

50

0.000

0.010

0.020

0.030

0.040

0.050

0.060

0.070Dual Trunkline Configuation

Max gas vol- pressure d...

Nominal Diameter,inches

Pres

sure

Dro

p,ba

ra

Vol

-Hol

dup

Frac

tion

Graph 4.3.2








Based on the above observations, 14” trunkline is selected as a optimum pipeline

size in dual trunkline configuration.

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4.4 Trunkline selection

Dual trunk line configuration has added advantage over Single trunk line

configuration as listed below:

Increased turndown ability.

Allowing production at two independent pressure levels.

Dynamic Pigging.

Impact on slug catcher sizing (Through better liquid inventory control).

Round trip pigging.

Depressurisation from both sides.

Simplified dewatering and start-up.

Based on above considerations, Dual trunk line configuration in 14” ND is chosen as

the trunkline for this case study.

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4.5 Inhibitor requirements

For the given compositions of dry and condensate gas, hydrate curves are

generated in PVT-Sim as shown in the below graph. The area towards left side of

the graph is the hydrate formation zone. During operation phase, the reservoir fluids

in the pipeline should be away from this zone. By adding thermodynamic hydrate

inhibitors, the hydrate curve is shifted towards left side, thereby moving the pipeline

fluids out of hydrate formation zone. The degree of temperature reduction required to

inhibit hydrate formation at a given pressure is called depression in hydrate

temperature.

As discussed in the later sections of this document, due to difference in type of

hydrates (due to difference in composition), gas condensate forms hydrate at higher

temperatures for the given pressure i.e higher degree of cooling is required.

0 5 10 15 20 250

50

100

150

200

250

Gas Condensate

Dry Gas

Temperature *C

Pres

sure

, bar

a

Graph 4.5.1

As detailed in section 4.5, Minimum seabed temperature are in the range of 3oC.

From the above graph, for 3oC temperature, minimum pressure required for the

hydrate formation is in the range of 20 – 35 bara. Since the wellhead pressures are

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in the range of 230-80 bar during the field life, continuous injection of hydrate

inhibitor at wellheads is required to prevent hydrate formation.

MEG is chosen as the hydrate inhibitor and is to be continuously injected at

wellheads to avoid hydrate formation during normal operation and shut down

condition.

Based on the Hammer Schmidt equation, with K=2335, below tables gives the

required amount of MEG injection rate at wellhead year wise for dry gas and gas

condensate composition.

Dry Gas Composition

Year

Depression in

Hydrate temp, oC

Total Water, m3/da

y

Rich MEG Wt%

90/10 Lean MEG in M3 per DayTotal Lean MEG

m3/day

Total Rich MEG

m3/day

Well A

Well B

Well D

Well E

Well F

0 17 20 44 3 3 3 3 3 17 37

1 16 77 43 13 13 13 13 13 66 143

2 15 134 42 22 22 22 22 22 109 243

3 14 161 41 29 29 29 29 29 146 307

4 13 162 39 18 18 18 18 18 88 250

5 11 188 34 21 21 21 21 21 105 293

6 10 216 33 17 17 20 20 20 95 311

7 8 86 28 9 9 9 9 9 44 130

8 7 98 25 8 8 8 8 8 42 140

Table 4.5.1

For Gas condensate:

Year

Depression in

Hydrate tempoC

Total Water,m3/da

y

Rich MEGWt%

90/10 Lean MEG in M3 per Day Total Lean MEG

m3/day

Total Rich MEG

m3/day

Well A Well B Well D Well E Well F

0 21 20 50 4 4 4 4 4 22 41

1 20 78 49 17 17 17 17 17 84 161

2 20 135 48 28 28 28 28 28 142 277

3 19 161 47 39 39 39 39 39 196 357

4 18 162 47 25 25 25 25 25 124 286

5 17 188 44 28 28 28 28 28 140 328

6 16 216 43 31 31 31 31 31 155 371

7 15 86 42 17 17 17 17 17 85 171

8 14 98 40 18 18 18 18 18 91 188

Table 4.5.2

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4.6 Arrival pressures

In forward approach, for the given wellhead pressures, arrival pressures at the host

facility are calculated by steady state approach.

In this approach, timing of compression and rating of the host facility is determined.

Based on the selected infield and trunkline sizes, arrival pressures at host facility are

calculated for dry gas and gas condensate composition as shown below.

0 1 2 3 4 5 6 7 8 90

40

80

120

160

200

0

2

4

6

8

10

12Dry Gas - Arrival Pressure - Forward Approach

PRESSURE

Flow rate (MMSCMD)

Year

Arriv

al p

ress

ure

(bar

a)

Flow

Rat

e, M

MSC

MD

Graph 4.6.1

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0 10 20 30 40 50 600

50

100

150

200

250

0

5

10

15

20

25

30

35

40Dry Gas - Arrival Pressure - Year 0

Pressure, bara

Fluid temp, *C

Ambient temp

Hydrate formation temp *C

Length,km

Pres

sure

, bar

a

tem

pera

ture

,oC

Graph 4.6.2

0 10 20 30 40 50 600

50

100

150

200

250

0

5

10

15

20

25

30

35

40

45

Dry Gas - Arrival Pressure - Year 4

Pressure , bara

Fluid temp, *C

Ambient temp

Hydrate formation Temp *C

Length,km

Pres

sure

, bar

a

tem

pera

ture

,oC

Graph 4.6.3

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0 10 20 30 40 50 600

50

100

150

200

250

0

5

10

15

20

25

30

35

40

45Dry Gas - Arrival Pressure - Year 8

Pressure , bara

Fluid temp, *C

Ambient temp

Hydrate formation temp *C

Length ,km

Pres

sure

, bar

a

tem

pera

ture

,oC

Graph 4.6.4

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Gas condensate

0 1 2 3 4 5 6 7 8 90

20

40

60

80

100

120

140

160

180

0

2

4

6

8

10

12Forward Approach

Arrival Pressure at OT

Flow rate, MMSCMD

Year

Pres

sure

, bar

a

Flow

rate

, MM

SCM

D

Graph 4.6.5

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0 10 20 30 40 50 60 700

50

100

150

200

250

0

10

20

30

40

50

60

70

80Gas Condensate - Arrival Pressure - Year -0

Pressure ,barFluid temp,*CAmbient temp, *CHydrate temp*C

Length,km

Pres

sure

,bar

a

Tem

pera

ture

,*C

Graph 4.6.6

0 10 20 30 40 50 60 700

20

40

60

80

100

120

140

160

0

10

20

30

40

50

60

70

80Gas Condensate - Arrival Pressure - Year 4

Pressure,bar

Fluid temp,*C

Ambient temp,*C

Hydrate temp, *C

Length,km

Pres

sure

,bar

a

Tem

pera

ture

,oC

Graph 4.6.7

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0 10 20 30 40 50 60 700

10

20

30

40

50

60

70

80

0

10

20

30

40

50

60

70

80Gas Condensate - Arrival Pressure- Year 8

Pressure,bar

Fluid temp,*C

Ambient temp,*C

Hydrate temp, *C

Length,km

Pres

sure

,bar

a

Tem

pera

ture

,oC

Graph 4.6.8

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4.7 Arrival Pressures-Backward Approach

Depending on the arrival pressures in forward approach and host facility pressure requirements, in backward approach, wellhead pressures (Choke downstream) are calculated.

In this approach, pressure drop across the system is evaluated and then the excess pressures are choked at the wellheads.

The arrival pressures at the host facility and arrival temperature along with degree of choking at the wellheads are shown in the following graphs for both Dry and Gas Condensate composition.

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DRY GAS

0 2 4 6 8 1030

50

70

90

110

130

150

170

190

210

230Arrival Pressure- Backward Approach

Max THP Min THP Avg Choke d/s

Year

Pres

uure

, bar

a

Graph 4.7.1

GAS CONDENSATE

0 1 2 3 4 5 6 7 8 90

20

40

60

80

100

120

140

160

0

2

4

6

8

10

12Arrival Pressure- Backward Approach (Gas Condensate)

Pressure in reservoir

Flow rate

Year

Pres

sure

,bar

Flow

rate

, MM

SCM

D

Graph 4.7.2

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4.8 Timing of compression and compressor power requirement

YearFlow rate, MMSCMD

Arrival Pressures, bara

Compression Discharge

Compression Power (MW)

Dry Gas Gas Condensate Dry GasGas

Condensate

0 10 80 80 76 - -

1 10 80 80 76 - -

2 10 80 80 76 - -

3 7.5 80 80 76 - -

4 6.5 80 80 76 - -

5 6 70 62 76 3 4

6 5.8 47 38 76 8 9

7 2 58 53 76 2 2

8 2 49 45 76 2 3

Table 4.8.1

Condensate Production at OT

Year MMSCMD bbl/day m3/day

0 10 1887 300

1 10 1887 300

2 10 1887 300

3 8 1415 225

4 8 1415 225

5 6 1132 180

6 6 1094 174

7 2 377 60

8 2 377 60

Table 4.8.2

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V.0 Facilities required for processing hydrocarbon fluids:

Some of the major functions performed by the host Facility (OGPT) are:-

I. Facility to separate and collect liquid slugs from the gas coming from subsea pipelines.

II. Phase separation of Rich MEG from hydrocarbon condensate.III. Dehydrate the gas to meet the sales gas specification.IV. Compression and fiscal metering of sales gas.V. Regeneration of MEG to the required purity and pump to re-inject Lean MEG

at subsea facilities.VI. Removal and disposal of salts removed from reclaimed MEG.

VII. Produced water treatment and disposal of treated effluent water.VIII. Hydrocarbon condensate handling unit, storage facility, and hydrocarbon dew

point depression unit

Processing Facilities:

a. Pig Receiver/Launcher: A PIG is used for cleaning and inspection.b. Slug Catcher: Slug catcher separates gas and rich MEG and provides temporary

storage for rich MEG.c. Gas Filter Coalesce: For reducing entrained rich MEG content in gas to less than

0.05 ppm (wt). Gas Filter Coalescer is installed downstream of the production separator. This vessel has horizontal orientation.

d. Gas Dehydration unit: The wet gas coming from Gas Filter Coalescer is fed to the TEG Contactor Column. The wet gas rises through structured packing medium where it contacts the descending lean (dry) TEG that absorbs the moisture from the wet gas. The dry gas exits from the top of the TEG contactor and rich TEG leaves through the bottom of the contactor. The TEG Dehydration system comprises of :

TEG contactor Gas/TEG Exchanger TEG Regeneration Unit

Metering: The metering package is provided to record the sales gas flow. It is multi-path ultra sonic flow meter with gas chromatography and moisture analyzer for online analysis of gas. A single buy-back gas meter is provided to measure flow of gas to OT during black-start up.

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BLOCK DIAGRAM FOR GAS & CONDENSATE PROCESSING AT OT

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Pressure Reducing Station 1

Pressure reducing station 2

Slug Catcher 1

Slug Catcher 2

Production separator

MEG reclamation

Lean MEG storage tank

Lean MEG injection pump

Lean MEG to Sub-sea Pipeline

Pipeline #2

Gas filter Coalescer #1 TEG

Contactor

TEG Regeneration

Custody Transfer Metering

Sales Gas Compressor

Effluent Treatment Plant

Treated Effluent Pond

Sales gas to Main Pipeline

Pipeline #1

Three Phase Separator

Oil to condensate stabilization

Inlet Gas heater

Red indicates additional facilities required if the fluid composition is of gas condensate.

Figure 2

Annexure

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Appendix 1

MULTIPHASE FLOW

IntroductionThe simultaneous flow of gas and liquid through pipes, often referred to as multiphase flow, occurs in almost every aspect of the oil industry. Multiphase flow is present in wellbore tubing, gathering system flowlines, and processing facilities and has become increasingly important in recent years due to the development of marginal fields and deepwater prospects. In many cases, the feasibility of these prospects/fields hinges on cost and operation of the pipelines and the associated equipment. Multiphase flow characteristics can have a profound effect on both the design and operation of these systems. For example,the type of flow regime (described in Section 5.2) can affect the pressure drop along a pipeline. The amount of the pressure drop can affect either pipe size and/or pumping requirements depending on the scenario. Multiphase flow in pipes has been studied for more than 50 years, with significant improvements in the state of the art during the past 15 years. The best available methods can predict the type of multiphase flow characteristics much more accurately than those available only a few years ago. The designer, however, has to know which methods to use to get the best results. The objective of this section is to present the basic principles of multiphase flow and illustrate the current methods available to predict multiphase flow regimes, pressure drop and liquid holdup. This chapter is arranged in the following order. Flow regimes are discussed and described in Section 5.2. Section 5.3 describes the flow models used to predict the flow regimes. The calculation of pressure drop and liquid holdup based on the flow regime is discussed in Sections 5.4 and 5.5. Section 5.6 illustrates the effects of three phases.

5.2 Flow RegimesIn multiphase flow, the gas and liquid within the pipe are distributed in several fundamentally different flow patterns or flow regimes, depending primarily on the gas and liquid velocities and the angle of inclination. In general, flow regimes are split into two major categories based on geometry: horizontal and vertical. The term "horizontal" is used to denote a pipe that is inclined in a range between plus or minus 10 degrees. The term "vertical" denotes upward inclined pipes with angles from 10 to 90 degrees from horizontal. Observers have labeled these flow regimes with a variety of names. Over 100 Different names for the various regimes and sub-regimes have been used in literature. In this guide, only four flow regime names will be used: slug flow, stratified flow, annular flow, and dispersed bubble flow. Figure 5.2-1 shows the flow regimes for near horizontal flow, and Figure 5.2-2 shows the flow regimes for vertical upward flow. Descriptions of the flow regimes are as follows: 5.2.1 Stratified Flow Stratified Flow generally occurs at low flow rates in near horizontal pipes. Theliquid and gas separate by gravity, causing the liquid to flow on the bottom of the pipe while the gas flows above it. At low gas velocities, the liquid sur face is smooth. At higher gas velocities, the liquid surface becomes wavy. Some liquid may flow in the form of liquid droplets suspended in the gas phase. Stratified flow only exists for certain angles of inclination. It does not exist in pipes that have upward inclinations of greater than about one degree. Most downwardly inclined pipes are in stratified flow, and many large diameter horizontal pipes are in stratified flow. This flow regime is also referred to as stratified smooth,stratified wavy, and wavy flow by various investigators.

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5.2.2 Annular FlowAnnular flow occurs at high rates in gas dominated systems. In annular flow part of the liquid flows as a film around the circumference of the pipe. The gas and remainder of the liquid (in the form of entrained droplets) flow in the center of the pipe. The liquid film thickness is fairly constant for vertical flow, but it is usually asymmetric for horizontal flow due to gravity. As velocities increase, the fraction of liquid entrained increases and the liquid film thickness decreases. Annular flow exists for all angles of inclinations. Most gas-dominated pipes in high pressure vertical flow are in annular flow. This flow regime is also referred to as annular-mist or mist flow by many investigators.5.2.3 Dispersed Bubble Flow Dispersed bubble flow occurs at high rates in liquid dominated systems. The flow is a frothy mixture of liquid and small-entrained gas bubbles. For near vertical flow, dispersed bubble flow can also occur at more moderate liquid rates when the gas rate is very low. The flow is steady with few oscillations. It occurs at all angles of inclination. Dispersed bubble flow frequently occurs in oil wells. Various investigators have also referred to this flow regime as froth or bubble flow. 5.2.4 Slug FlowSlug flow for horizontal flow usually occurs at moderate gas and liquid velocities. Slugs form due to high vapor shear causing the development of waves on the surface of the liquid to grow to a sufficient height to completely bridge the pipe. When this happens, alternating slugs of liquid and gas bubbles will flow through the pipeline. This flow regime can be thought of as an unsteady, alternating combination of dispersed bubble flow (liquid slug) and stratified flow (gas bubble). The slugs can cause vibration problems, increased corrosion, and downstream equipment problems due to its unsteady behavior. Slug flow also occurs in near vertical flow, but the mechanism for slug initiation is different. The flow consists of a string of slugs and bullet-shaped bubbles (called Taylor bubbles) flowing through the pipe alternately. The flow can be thought of as a combination of dispersed bubble flow (slug) and annular flow (Taylor bubble). The slugs in vertical flow are generally much smaller than those in near horizontal flow. Slug flow is the most prevalent flow regime in low pressure, small diameter systems. In field scale pipelines, slug flow usually occurs in upwardly inclined sections of the line. It occurs for all angles of inclination. Investigators have used many terms to describe parts of this flow regime. Among them are intermittent flow; plug flow; pseudo slug flow, and churn flowFlow regime for near horizontal flow

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Flow regime for vertical flow

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Appendix 2

Phase Behaviour

Reservoir fluids are often described in terms of their phase behavior, which can be Defined as the relationship between the fluid phases (usually the gas and the oil/condensate) and how the phases change with variations in temperature and pressure.Single Component Phase BehaviorIn describing phase behavior, a system consisting of a single, pure substance is considered first. Such a system behaves differently from systems made up of more than one component. A phase diagram (or phase envelope) is a plot of pressure versus temperature showing the conditions under which the various phases will be present.

Phase Diagram for a Single-Component System

This phase diagram shows the temperature and pressure conditions under which the vapor, liquid, and solid phases exist. Various components of the phase diagram are defined below.

Vapor Pressure CurveThe curve that divides the vapor phase from the liquid phase is called the vapor pressure curve. At conditions above the curve only liquid will exist, and at conditions below the curve only vapor exists. At pressure-temperature points on the curve, vapor and liquid will co-exist.

Triple PointThe triple point is a unique point on the phase diagram at which vapor, liquid, and solid all coexist.

Critical PointThe upper limit of the vapor pressure curve is called the critical point. The temperature and pressure at this point are referred as to the critical temperature (Tc) and the critical pressure (Pc).

Sublimation and Melting CurvesThe phase diagram also illustrates the sublimation curve and melting curve, which separate the solid and gas phases and the liquid and solid phases, respectively.

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Multicomponent Phase Behavior

Reservoir fluids are multicomponent mixtures and exhibit more complex phase behavior than pure components. Below figure illustrates a phase diagram for a gas-condensate system. This diagram does not include potential solid phases that occur in reservoir fluids; the diagram focuses only on the vapor and liquid phases. Instead of a single curve representing the vapor pressure curve as with single component fluids, there is a broad region in which vapor and liquid coexists. This region is called the two-phase region or phase envelope. The two-phase region is bounded on one side by the dew point curve and on the other by the bubble point curve. The two curves join at the critical point.

Multiple Component Phase Diagram

Dew Point and Bubble PointAt a pressure below the dew point curve, the fluid will be single-phase vapor. As the pressure is increased at a constant temperature, the vapor compresses until the pressure reaches a point at which the first drop of liquid is formed. This is referred to as the dew point. The pressure at which the first liquid drop forms is called the dew point pressure. As the pressure is increased above the dew point pressure, more and more liquid forms. At a pressure above the bubble point curve, the fluid will be single-phase liquid. As the pressure is reduced at a constant temperature, the liquid expands until the pressure reaches a point at which the first bubble of vapor is formed. This is referred to as the bubble point. The. Pressure at which the first gas is formed is the bubble point pressure. As the pressure is decreased below the bubble point pressure, more and more gas appears.

Critical PointAs can be seen when comparing the definition for the critical point for a single component is not the same as that for a multiple component mixture. A rigorous definition of the critical point is that it is the point at which all properties of the liquid and the gas become identical.

55 | P a g e

Cricondentherm and Cricondenbar

The highest temperature on the two-phase envelope is called the cricondentherm. Thehighest pressure on the two-phase envelope is called the cricondenbar.

Quality LinesAnother feature in the two-phase envelope are quality lines. These lines indicate curves on constant vapor or liquid quantities within the two-phase region. There are quality lines for 99, 95, 90 and 80 mole percent vapor. The quality lines all converge at the critical point.

Retrograde CondensationFor many multiple component mixtures a phenomenon called retrograde condensation can occur. If the mixture is at a pressure greater than the cricondenbar and at a temperature greater than the critical temperature, it will be single-phase gas. If the pressure is decreased isothermally, the dew point curve will be crossed and liquid will form. A decrease in pressure has caused liquid to form; this is the reverse of the behavior one would expect, hence the name retrograde condensation. As the pressure continues decreasing, more liquid will form until at some pressure the amount of liquid starts decreasing. Eventually the dew point curve will be crossed again.

Dense Phase RegionIt is common practice to refer to the area above the cricondenbar as the dense phase region. In this region it possible to move from a temperature well below the critical temperature to one well above it without any discernible phase change having taken place. At the lower temperature the fluid would behave more like a liquid and at the higher temperature it would behave more like a vapor, but in between it would not exhibit any of the traditional signs of a phase change.

Components of Reservoir Fluids Reservoir fluids contain a multitude of chemical components, which can be divided intoTwo groups: hydrocarbons and non-hydrocarbons. The hydrocarbon components include:

Paraffins (straight chain and branched)Methane, ethane, propane, butanes, pentanes, hexanes, heptanes, octanes, etc.WaxesNaphthenesCyclopentane, cyclohexane, methylcyclohexane, etc.

AromaticsBenzene, toluene, xylenes, ethylbenzene, naphthalene, etc.

Resins and Asphaltenes

Large molecules composed mainly of aromatic rings or carbon and hydrogen but also can contain nitrogen, sulfur, oxygen, and metals

The non-hydrocarbon components of reservoir fluids include: Water

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Carbon dioxide (CO2) Sulfur compounds Hydrogen sulfide (H2S), mercaptans Nitrogen (N2) Helium Metals Vanadium, nickel Mineral salts

Types of Reservoir FluidsFive types of reservoir fluids can be defined: black oil, volatile oil, retrograde gas, wet gas, and dry gas. These five types of reservoir fluids have been defined because each requires different approaches for reservoir management and production system design.

The reservoir fluid type can be confirmed only by observation in the laboratory; however, some rules of thumb can help identify the fluid type. Three properties that can be used with the rules of thumb are the initial producing gas-oil ratio, the gravity of the stock tank oil, and the color of the stock tank oil. The behavior of a reservoir fluid during production is determined by the shape of its phase diagram and the position of its critical point. Each of the five reservoir fluid types can be described in terms of its phase diagram.

Black OilsThe phase diagram for a black oil is presented in below figure. Indicated on the phase diagram is the critical point and quality lines. The vertical line in the figure indicates the pressure reduction at constant temperature that occurs in the reservoir during production. As the reservoir of a black oil is produced, the pressure will eventually drop below the bubble point curve. Once below the bubble point, gas evolves from the oil and causes some shrinkage of the oil. Black oils are characterized as having initial gas-oil ratios (GORs) of 2000 SCF/STB or less. The producing gas-oil ratio will increase during production when reservoir pressure drops below the bubble point pressure. The stock tank oil will usually have a gravity below 45API. The stock tank oil will be very dark due to the presence of heavy hydrocarbons.

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Volatile OilsThe phase diagram for a typical volatile oil, is somewhat different from the black-oil phase diagram. The temperature range covered by the two-phase region is somewhat smaller, and the critical point is much lower than for a black oil and is relatively close to the reservoir temperature (but still greater than the reservoir temperature). The vertical line in the figure shows the reduction in reservoir pressure at constant temperature during production. For a volatile oil, a small reduction in pressure below the bubble point can cause a relatively large amount of gas to evolve. The dividing line between black oils and volatile oils is somewhat arbitrary. Volatile oils may be identified as having initial producing GORs between 2000 and 3300 SCF/STB. The stock tank oil gravity is usually 40API or higher, and the stock tank oil is colored (usually brown, orange, or green).

Retrograde GasesThe phase diagram of a retrograde gas shown below has a somewhat smaller temperature

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range than that for oils, and the critical point is further down the left side of the phase envelope. The changes are a result of retrograde gas containing fewer heavy hydrocarbons than the oils. Additionally, the critical temperature is less than the reservoir temperature, and the cricondentherm is greater than the reservoir temperature. During initial production, the retrograde gas is single-phase gas in the reservoir. As the reservoir pressure declines, the dew point is reached, and liquid begins to condense from the gas and form a free liquid in the reservoir. This liquid will normally not flow and cannot be produced. The initial producing GORs for a retrograde gas ranges from 3300 SCF/STB on the lower end to over 150,000 SCF/STB (the upper limit is not well defined). The producing GOR will increase after the reservoir pressure drops below the dew point. Stock tank gravities of the condensate are between 40 and 60API and increase as reservoir pressure drops below the dew point. The stock tank liquid will be lightly colored to clear.

Wet GasesWith wet gases the entire phase envelope will be below the reservoir temperature as Illustrated in the following figure. Wet gases contain predominately low molecular weight molecules.Wet gases will remain as single phase gas in the reservoir throughout the production life; however, the separator conditions do lie within the two-phase region. Thus, somewhere in the production system, the dew point curve will be crossed and liquid will condense from the gas. Wet gases produce stock-tank liquids with gravities ranging from 40 to 60API; however, the gravity of the liquid does not change during the production life. Wet gases have very high GORs, typically more than 50,000 SCF/STB.

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Dry GasesDry gases are primarily methane with some light intermediates. Below figure shows thatthe two-phase regions is less than the reservoir conditions and the separator conditions.Thus no liquid is formed in either the reservoir or the separator.

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Appendix 3

Latest Simulation Softwares were used to perform pipeline profiling and field architecture, the simulation softwares include

INPLANT PIPEPHASE OLGA 2000

INPLANT: The INPLANT program is a steady-state, fluid flow simulator for designing, rating and analyzing plant piping systems. Engineers can quickly rate and analyze the safety of plant piping systems via the INPLANT Graphic User Interface for Microsoft Windows operating systems. INPLANT also enables the design of new piping systems or the revamp of a wide variety of existing systems. Applications range from simple, single pipe sizing and rating calculations to large, multiphase fluid piping networks with complex, nested-loop technology. INPLANT easily solves relief system problems involving networks with single or multiphase fluids at high velocities or in critical flow.

PIPEPHASE: PIPEPHASE software is a simulation program which predicts steady-state pressure, temperature, and liquid holdup profiles in wells, flowlines, gathering systems, and other linear or network configurations of pipes, wells, pumps, compressors, separators, and other facilities. The fluid types that PIPEPHASE software can handle include liquid, gas, stream, and multiphase mixture mixtures of gas and liquid.

OLGA 2000: OLGA has full network capability, that is, it handles both diverging and converging networks. Complete topside process systems can therefore be simulated. The dynamic capability of OLGA is its most important feature. Multiphase flow is a dynamic phenomenon and should be modelled as such. This dynamically increases the range of applicability compared with steady state models. OLGA is capable of compressors, pumps, heat exchangers, separators, checkvalves, controllers and mass sources/sinks.

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APPENDIX 4

Hydrate Mitigation

History

Hydrates of natural gas were first discovered by Sir Humphrey Davy in 1810 but remained somewhat of a scientific curiosity until Hammerschmidt reported in 1934 that they could form in natural gas pipelines leading to blockages and reduced or no gas flow. The initial work by hammerschmidt motivated considerable research activity in the formation of hydrates and their prevention in pipelines and led to the development of the first hydrate prediction methods and inhibition techniques.In this last decade, driven by the need to cut operation cost and reduce environmental impact of operating oil &gas facilities, research activity has concentrated on the development novel low dosage hydrate inhibitors (LDHIs). This report presents are reviews of alternative hydrate mitigation methods focusing on the prediction methods required for design and the selection criteria applicable for different field development scenarios.

Introduction

This report reviews the strategies for hydrate mitigation and remediation focussing on novel chemical inhibitors and the prediction of hydrate formation and dislocation. The application of novel low dosage inhibitors is analysed and the current advantages and disadvantages are highlighted. The predictive modelling of hydrate formation is also discussed and the strengths and weaknesses of the techniques are evaluated. The discussion concludes that the novel hydrate inhibitors offer significant cost and environment benefits compared to the traditional chemicals, but that they still suffer from a number of important limitations which restrict widespread application. From the modelling perspective, the paper emphasises the need for improved modelling, particularly in black oil systems, and the need for work on the modelling of novel inhibitor effects.

Gas hydrate are crystalline ice- like solids formed from water and a range of lower molecular weight molecules, typically methane, ethane, propane, hydrogen sulphide and carbon dioxide. The structures of the crystals fall into the class of clathrates with the water molecule forming hydrogen- bonded cage like structure which is stabilized by “guest” Molecules located within the lattice. To date there are three known hydrate structures referred to as structure I, II and H (abbreviated to sI, sII and sH).

Structure I hydrates contain 46 water molecules per 8 gas molecules giving a hydrate number of 5.75

Structure II hydrates contains 136 water molecules per 24 gas molecules giving a hydrate number of 5.67

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The water molecules form 16 small dodecahedral voids and 8 large hexakaidecahedral voids. The larger voids are able to accommodate molecules including propane, isobutene, cyclopentane, benzene and others

Structure H hydrates were discovered recently and contain 34 water molecules for every 6 gas molecules giving a hydrate number of 5.67.

Hydrate Mitigation and remediation

The various methods of hydrate control can be summarised as follows :-

a) Pressure controlDesign and operate the system with pressures low enough to maintain the fluids outside the hydrate envelope. This approach is often impractical for normal operation since the pressure required for transportation of production fluids would usually exceed the hydrate formation pressure at ambient temperature.

b) Temperature controlMaintain the temperature of the production fluids by either passive insulation or active heating in order to prevent the system entering the hydrate envelope. However temperature control by passive insulation only offers hydrate control during normal operation when the system is continuously is being continuously heated by hot production fluids.

c) Remove supply of waterPrevent the formation of hydrate by removing the supply of water using separation and dehydration. This approach has proved popular for the export of sales but is impractical for subsea applications.

d) Remove supply of hydrate formersPrevent the formation of hydrates by removing the supply of hydrate forming molecules perhaps by gas-liquid separation.

e) Inject chemical inhibitors Inject chemical inhibitors into the system which modify the hydrate phase diagram or the kinetics of hydrate formation.

Hydrate mitigation with chemical Inhibitors

The various chemicals available for hydrate prevention fall into three classes: Traditional thermodynamic inhibitors, novel kinetic inhibitors and novel anti-agglomeration inhibitors.

Thermodynamic Hydrate Inhibitors (THIs) – These chemicals work by altering the chemical potential of the aqueous phase such that the equilibrium dissociation curve is displaced to

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lower temperatures and higher pressures. They are added at relatively high concentrations, Eg- Mono Ethylene Glycol (C2 H4 02).

Kinetic Hydrate Inhibitors (KHIs) – This class of chemicals does not alter the thermodynamics of hydrate formation but instead modifies the kinetics of hydrate formation. They achieve this both by prevention of nucleation and by hindering crystal growth.

Anti Agglomerants (AAs) – These chemicals do not seek to prevent hydrate formation but rather prevent the crystal from agglomerating and therefore forming a blockage. Their main limitation is that they require a continuous oil phase and are therefore available at lower Water cuts.

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References

Pickering P.F, Edmonds B, Moorwood R.A.S, Szczepanski R & Watson M.J 2007, EVALUATING CHEMICALS AND ALTERNATIVES FOR MITIGATING HYDRATES IN OIL AND GAS PRODUCTION.

V Martinez-Ortiz, SPT group, SIZING OF PIPELINES FOR GAS-CONDENSATE BY MULTIPHASE DYNAMIC SIMULATION, BASED IN MINIMUM, MEDIUM AND MAXIMUM FLOWRATES.

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CONCLUSION

Conclusions:

1. Calculating composition pressure and temperature is necessary to determine if there will be hydrates, wax, corrosion, and excessive pressure losses, etc.

2. Elevation in pipeline hydraulics is very important.3. Pipeline size matters. Bigger is NOT always better.4. Fluid properties are very important5. Gas composition plays critical role in pipeline hydraulics and

designing.

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Glossary

XMT: An assembly of valves, spools, pressure gauges and chokes fitted to the wellhead of a completed well to control production.

Wellhead: The surface termination of a well bore that incorporates facilities for installing casing hangers during the well construction phase. The wellhead also incorporates a means of hanging the production tubing and installing the Christmas tree and surface flow- control facilities in preparation for the production phase of the well.

Flowline: A surface pipeline carrying oil, gas or water that connects the wellhead to a manifold or to production facilities, such as heater-treaters and separators.

Manifold: A pipe fitting with several lateral outlets for connecting flowlines from one or more wells. This connection directs the flow to heat-treaters, separators or other devices.

Umbilical: An umbilical cable is a cable which supplies required consumables to an apparatus.

Deepwater pipelines: Deepwater pipeline refers to the pipelines laid in water depths greater than 1000 ft or 305 meters by US MMS (Mineral management services)

Trunk line: Trunklines are defined as the pipelines that transport the total production from gathering systems (manifold) to the host facility.

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