1. Cranfield University
School of Energy, Environment and Agrifood
Offshore and Ocean Technology MSc
Low Cost Subsea Processing System
for Brownfield Developments
Academic year : 2014-2015
Industrial Partner: INTECSEA
Academic Supervisor: Dr. Fuat Kara
Delphine GALL
Alberto GUIJARRO RODRIGUEZ
Kelvin Chidozie OKOLIEABOH
Patrick C. OSERE
Peter OVUOMARAHASU
Andr´e S.N.PIAZZINI
Olawale B. SAMUEL
Moshood A.YAHAYA
27 April 2015

2. Cranfield University
School of Energy, Environment and Agrifood
Offshore and Ocean Technology MSc
Low Cost Subsea Processing System
for Brownfield Developments
Academic year : 2014-2015
Industrial Partner: INTECSEA
Academic Supervisor: Dr. Fuat Kara
Delphine GALL
Alberto GUIJARRO RODRIGUEZ
Kelvin Chidozie OKOLIEABOH
Patrick C. OSERE
Peter OVUOMARAHASU
Andr´e S.N.PIAZZINI
Olawale B. SAMUEL
Moshood A.YAHAYA
This thesis is submitted in partial fulfilment of the requirements for
the degree of MSC Offshore and Ocean Technology.
©Cranfield University 2015. All rights reserved. No part of this publication
may be reproduced without the written permission of the copyright owner.
27 April 2015

3. Executive Summary
Many topside processing facilities are currently capacity constrained due to the volumes of produced
water that requires treatment. This is backing out potential oil production from other satellite dis-
coveries. Reducing the amount of produced water requiring topside treatment would debottleneck
the topside facilities, increase oil handling capacities and also create space for additional production
and tieback of surrounding marginal fields. A viable option of addressing these challenges is through
Subsea Processing.
Some of the fields challenged with high water cut are brownfield with limited operational life, hence
it could be capital intensive and uneconomical to invest in full subsea processing at such stage of a
field’s life. It therefore become necessary to develop a low cost subsea processing system that could
be economically suitable for brownfield development. This is the focus of this work.
An examination of existing subsea processing technologies and their suppliers were made and their
advantages and limitation in brownfield application were assessed. Two different subsea processing
system configuration options were proposed and analysed. An analysis of the various equipment
building blocks such as separators, pumps, compressors, sand handling and water treatment unit
were performed and the chosen options justified.
A numerical simulation with matlab was performed to determine the sizing and capacity of a 3-
phase gravity-based separator considered to be the preferred separator choice. The pump net positive
suction pressure and pump power requirement was calculated for different water depths, total pipeline
distance, flowrate and water cut. Furthermore, Hysys simulation was used to analyse the hydrocarbon
data from balmoral field, UK which was used as a case study for this project.
Finally, a low cost subsea processing system for brownfield development comprising of a three phase
gravity-based separator, oil and gas boosting pump and a water re-injection pump was proposed.

4. Acknowledgement
The members of Group D would like to appreciate everyone who has assisted us in the successful
completion of this group project.
We are grateful to John Purdue and Ronald Doherty of INTECSEA UK Ltd for their dedication
and relentless effort in monitoring our progress, and providing us with every necessary technical as-
sistance, useful literatures and field data.
Our heartfelt gratitude also goes to, Engr. Basil Akpan of Westfield Subsea Ltd, who facilitated
the success of this group work by providing us with directions and vital industry information.
Also, we appreciate Professor Guy Kirk for the feedback sessions he gave to the team members.
He undoubtedly helped every group member of this team improve their technical and soft skills which
was helpful in the successful delivery of this project.
Special thanks goes to our academic supervisors, Dr. Fuat Kara and Dr. Mahmood Shafiee of
Cranfield University for their support, guidance and encouragement in completing this work.
Finally, we appreciate every member of the team for their selfless contribution to the group and
the high level of cooperation, understanding and diligence shared amongst the group. We anticipate
working again in the future.

5. Table of Contents
1 Project Introduction 1
1.1 Background of Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2 Why Subsea Processing ? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.3 History and Evolution of Subsea Processing . . . . . . . . . . . . . . . . . . . . . . . . 3
1.4 Major Suppliers of Subsea technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1.5 Project Aim . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1.6 Project Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1.7 Project Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1.8 Concepts Design Philosophy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
2 System Configuration 8
2.1 Technical Option One . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.2 Technical Option Two . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.3 Selection of the Low Cost Subsea Processing System Configuration . . . . . . . . . . . 10
3 Subsea Processing Technologies 11
3.1 Subsea Separators and Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
3.1.1 Gravity Separator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
3.1.1.1 Design Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
3.1.1.2 Performance Impediments . . . . . . . . . . . . . . . . . . . . . . . . . 15
3.1.2 Compact and Dynamic Separator . . . . . . . . . . . . . . . . . . . . . . . . . . 16
3.1.2.1 Cyclonic Separators . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
3.1.2.2 Hydrocyclone Separator . . . . . . . . . . . . . . . . . . . . . . . . . . 19
3.1.2.3 Compact Electrostatic Coalescer (CEC) . . . . . . . . . . . . . . . . . 21
3.1.2.4 In-line or Pipe Separators . . . . . . . . . . . . . . . . . . . . . . . . . 21
3.1.3 Semi Compact Gravity Separation System . . . . . . . . . . . . . . . . . . . . . 23
3.1.4 Caisson Separation System and Vertical Annular Separation and Pumping Sys-
tem (VASP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
3.1.5 Comparison of Separator Technologies . . . . . . . . . . . . . . . . . . . . . . . 24
3.1.6 Technology Manufacturers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
3.2 Subsea Pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
3.2.1 Single Phase Pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
3.2.2 Multiphase Pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
3.2.2.1 Advantages of Multiphase Pumping Technology . . . . . . . . . . . . 27
3.2.2.2 Multiphase Pumping Technologies . . . . . . . . . . . . . . . . . . . . 28
3.2.2.3 Electrical Submersible Pumps . . . . . . . . . . . . . . . . . . . . . . 29
3.2.2.4 Helico-axial Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
3.2.2.5 Twin Screw Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
3.2.3 Intallation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
3.2.4 Suppliers/Vendors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
3.2.5 Field Application/Operators . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
3.3 Sand Handling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
3.3.1 Sand Separation Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
3.3.1.1 Screen / Filter (Gravel Pack) . . . . . . . . . . . . . . . . . . . . . . . 35
3.3.1.2 Cyclonic (Desander, Inline) . . . . . . . . . . . . . . . . . . . . . . . . 35
3.3.1.3 Settling (Sand Jetting System) . . . . . . . . . . . . . . . . . . . . . . 38
3.3.2 Sand Removal/Disposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
3.3.3 The consequences of sand deposits . . . . . . . . . . . . . . . . . . . . . . . . . 40
3.3.4 Suppliers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

6. 3.4 Water Treatment Technologies for reinjection . . . . . . . . . . . . . . . . . . . . . . . 41
3.4.1 Seawater Treatment Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . 41
3.4.1.1 Topside Seawater Treatment . . . . . . . . . . . . . . . . . . . . . . . 41
3.4.1.2 Subsea Seawater Treatment . . . . . . . . . . . . . . . . . . . . . . . . 45
3.4.1.3 Subsea Produced Water Treatment Technology . . . . . . . . . . . . . 46
4 Proposed Subsea Processing System Building Blocks 49
4.1 Separator Selection Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
4.1.1 Balmoral Fluid Composition Analysis . . . . . . . . . . . . . . . . . . . . . . . 49
4.1.2 Separator Options Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51
4.1.2.1 Two Cyclones in Series . . . . . . . . . . . . . . . . . . . . . . . . . . 51
4.1.2.2 Cyclone and 2-Phase Separator in Series . . . . . . . . . . . . . . . . 52
4.1.2.3 Gravity Separator Options . . . . . . . . . . . . . . . . . . . . . . . . 53
4.1.2.4 Two-Phase Gravity Separator . . . . . . . . . . . . . . . . . . . . . . 54
4.1.2.5 Three-Phase Gravity Separator . . . . . . . . . . . . . . . . . . . . . . 55
4.1.3 Selection Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
4.1.4 Designing a Three Phase Gravity Separator . . . . . . . . . . . . . . . . . . . . 59
4.1.4.0.1 Operating Conditions . . . . . . . . . . . . . . . . . . . . . . 59
4.1.4.0.2 Produced Fluid Composition . . . . . . . . . . . . . . . . . . 59
4.1.4.0.3 Expected Water cut . . . . . . . . . . . . . . . . . . . . . . . 59
4.1.4.1 Calculation Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
4.1.4.1.1 Compresibility factor . . . . . . . . . . . . . . . . . . . . . . 60
4.1.4.1.2 Gas Viscosity . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
4.1.4.1.3 Souders & Brown Constant (K) . . . . . . . . . . . . . . . . 62
4.1.4.1.4 The Drag Coefficient . . . . . . . . . . . . . . . . . . . . . . 62
4.1.4.1.5 Gas Capacity & Liquid Capacity Requirements . . . . . . . . 63
4.1.4.1.6 Separator Dimensioning . . . . . . . . . . . . . . . . . . . . . 65
4.1.4.2 Separator’s Weight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
4.1.4.2.1 Body‘s Volume . . . . . . . . . . . . . . . . . . . . . . . . . . 66
4.1.4.2.2 Semi-spherical Tap Volume . . . . . . . . . . . . . . . . . . . 67
4.1.4.2.3 Design Thickness . . . . . . . . . . . . . . . . . . . . . . . . 67
4.1.4.3 Separator Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68
4.1.4.4 Efficiency of the separation process in the liquid phase . . . . . . . . . 69
4.1.4.4.1 Retention Time . . . . . . . . . . . . . . . . . . . . . . . . . 69
4.1.4.4.2 Particle Diameter . . . . . . . . . . . . . . . . . . . . . . . . 69
4.1.4.4.3 Water cut . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70
4.1.4.5 Analysis of the effects of the different variables involved in the design
process (sensitivity analysis) . . . . . . . . . . . . . . . . . . . . . . . 74
4.1.4.5.1 Separator’s Weight . . . . . . . . . . . . . . . . . . . . . . . . 75
4.1.4.5.2 Separator’s Efficiency and Expected Water Cut . . . . . . . 76
4.2 Chosen Pump Option for Oil Boosting . . . . . . . . . . . . . . . . . . . . . . . . . . . 79
4.2.1 Boosting Pump Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79
4.2.1.1 Separator’s Pressure Drop . . . . . . . . . . . . . . . . . . . . . . . . 79
4.2.2 Oil and Gas Multi Phase Boosting Pump Capacity . . . . . . . . . . . . . . . . 80
4.3 Sand Handling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
4.3.1 When to use it ? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
4.3.1.1 Sand Handling technologies for a low cost subsea processing system . 83
4.4 Water Reinjection System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
4.4.1 The Seawater Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
4.4.1.1 Topside seawater treatment . . . . . . . . . . . . . . . . . . . . . . . . 86
4.4.1.2 Subsea seawater treatment . . . . . . . . . . . . . . . . . . . . . . . . 87
4.4.1.3 Seawater Treatment Options Assessment . . . . . . . . . . . . . . . . 88

7. 4.4.2 The Produced Water Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . 91
4.4.2.1 Safely tolerable amount of oil in injected produced . . . . . . . . . . 92
4.4.2.2 Subsea De-oiling Technologies . . . . . . . . . . . . . . . . . . . . . . 92
4.4.3 The Injection Pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
4.4.4 Summary & Conclusion for water treatment and injection systems . . . . . . . 96
5 Conclusion and Recommendations 97
A Computational Code for Designing a 3 Phase Gravity Based Separator 99

8. List of Figures
1 Subsea Processing (Source:FMC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
2 Subsea separation and pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
3 Evolution of Seafloor well technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
4 Major Subsea Processing Projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
5 Subsea processing system configuration showing the equipments building block with
one production line and one topside water re-injection line. . . . . . . . . . . . . . . . 8
6 Subsea processing system configuration showing the equipments building blockwith two
production line and one topside water re-injection line. . . . . . . . . . . . . . . . . . . 9
7 subsea separator showing the input and output layout. . . . . . . . . . . . . . . . . . . 11
8 Ensepatec 3-phase separator: http://www.ensepatec.com/en/products/process-internals/three-
phase-separator-2.html, Accessed March 2015. . . . . . . . . . . . . . . . . . . . . . . . 12
9 Three Phase Vertical Gravity Separator [Mulyandasari, 2011]) . . . . . . . . . . . . . . 13
10 Three Phase Horizontal Gravity Separator [Mulyandasari, 2011]) . . . . . . . . . . . . 13
11 Typical Cyclonic Separator [BENAVIDES, 2012] . . . . . . . . . . . . . . . . . . . . . 17
12 Gas Liquid Cylindrical Cyclone [Slettebø, 2009] . . . . . . . . . . . . . . . . . . . . . . 18
13 Compact Cyclonic Degasser [Slettebø, 2009] . . . . . . . . . . . . . . . . . . . . . . . . 18
14 Hydrocyclone Separator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
15 Sketches of a reverse-flow, cylinder-on-cone cyclone with a tangential inlet . . . . . . . 20
16 Compact Electrostatic Coalescer (CEC) . . . . . . . . . . . . . . . . . . . . . . . . . . 21
17 Schematics of Inline Cyclonic Units: Phase Splitter (Left), Deliquidizer (Middle) and
Degasser (Right) [SPE, 2012] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
18 Inline Cyclonic Separation Equipment: Liquid/Liquid Separator (Top Left), Phase
Splitter (Top Right), Deliquidiser (Bottom Left), and Desander (Bottom Right) . . . . 23
19 Semi Compact Separator in Statoil’s Tordis Field . . . . . . . . . . . . . . . . . . . . . 23
20 The Inlet Block of the Caisson Separator Used in the Shell Perdido Field . . . . . . . 24
21 Multiphase Pumping Technologies currently utilized . . . . . . . . . . . . . . . . . . . 29
22 Schematic of an ESP system Source: Islam, (2005, p.6) . . . . . . . . . . . . . . . 30
23 HAP Compression Stage (Framo Engineering) . . . . . . . . . . . . . . . . . . . . . . . 31
24 Distribution of a TSP Internals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
25 Multiphase Pump Module installation by cable . . . . . . . . . . . . . . . . . . . . . . 33
26 Graph showing relationship between sand removal efficiency and the diameter of inline
Desander . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
27 A typical inline Desander, image source FMC Technologies inline Desander, accessed
22/04/2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
28 Desander (FMC Technologies) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
29 A wellhead Desander with oversized accumulator integrated into the well bay of a
production spar. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
30 Sand jetting for gravity settling systems . . . . . . . . . . . . . . . . . . . . . . . . . . 39
31 Sand handling treatment and disposal (FMC technologie: Sand Handling Brochure) . 40
32 Predicted typical oilfield production profile with (secondary Production) or without
(Primary Production) water injection. . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
33 Topside Seawater Treatment System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
34 Seawater Coarse Filter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
35 Coarse seawater filter package. (Courtesy of Cameron Process Systems) . . . . . . . . 43
36 TIMEX fine filters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
37 Deaeration Tower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
38 Solution with both the SWIT unit and an injection pump integrated into the same
subsea structure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
39 Aspen Hysys analysis Phase envelope Balmoral Fluid composition . . . . . . . . . . . 50

9. 40 Aspen Hysys analysis Critical Temperature: 226.2o and Pressure: 66.65 bar for Bal-
moral Fluid Composition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
41 Image above shows A (Gas / Liquid Cylindrical Cyclone) in series with B (Hydrocyclone) 51
42 Image above shows A (Gas/Liquid Cylindrical Cyclone) in series with B (2-Phase
Separator) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
43 Comparison between Horizontal and Vertical Separator . . . . . . . . . . . . . . . . . 54
44 Subsea Processing System Configuration with a Two Phase Gravity Separator . . . . . 54
45 Subsea Processing System Configuration with a Three Phase Gravity Separator . . . . 56
46 Typical Design Retention Times in Three Phase Separation [Bautista and Gamboa,
2011] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69
47 Water particle diameter as a function of the oil retention time . . . . . . . . . . . . . . 70
48 Cross Section of the Separator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71
49 Graphic representation of the above equation and its linear plus parabolic approximation 72
50 Expected water cut as a function of the particle diameter . . . . . . . . . . . . . . . . 74
51 Sized Separator Weight as a function of the retention time . . . . . . . . . . . . . . . . 76
52 Expected water cut, at different production levels with variable retention time . . . . 77
53 Variation of the efficiency and the expected water cut at different levels of initial water
cut and retention time values . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
54 Volume of Oil generated for every separator cycle, at different retention time levels . . 78
55 Required Pump Head Pressure and Power for Different Initial Water Cut levels, with
a constant incoming Flow of 21000bpd among Different Production Distances of the
Pipe System, for a Constant Depth of 200m . . . . . . . . . . . . . . . . . . . . . . . . 81
56 Required Pump Head Pressure and Power for Different Initial Water Cut levels, with
a constant incoming Flow of 21000bpd among Different Production Distances of the
Pipe System, for a Constant Depth of 200m . . . . . . . . . . . . . . . . . . . . . . . . 82
57 Mature Field Production Optimization [Bedwell et al., 2015] . . . . . . . . . . . . . . . 83
58 Typical Topside seawater injection system . . . . . . . . . . . . . . . . . . . . . . . . . 87
59 The Well Processing SWIT and The Seabox SWIT . . . . . . . . . . . . . . . . . . . . 88
60 The Sorbwater Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
61 Inline Hydrocyclones . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
62 Assessment Matrix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
63 Produced Water Treatment Technologies Assessment Summary . . . . . . . . . . . . . 93
64 Processing system with Produced Water Treatment . . . . . . . . . . . . . . . . . . . . 94
65 Final Configuration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

10. List of Tables
1 Recent Subsea Processing and boosting installations . . . . . . . . . . . . . . . . . . . 5
2 Comparison between the identified low cost subsea processing system configuration
options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
3 Advantages and disadvantages of horizontal and vertical separators . . . . . . . . . . . 14
4 Internal Devices and Separation Aids for Separators . . . . . . . . . . . . . . . . . . . 16
5 Dimension of Standard Cyclone, Columns (1) and (5) = Stairmand, 1951; Columns
(2), (4) and (6) = Swift, 1969; Column (3) and sketch = Lapple, 1951 . . . . . . . . . 20
6 Comparison of In-line or Pipe Separators . . . . . . . . . . . . . . . . . . . . . . . . . 22
7 Advantages of multiphase pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
8 Advantages and limitations of Electrical Submersible Pumps . . . . . . . . . . . . . . 30
9 Advantages and limitations of Helico-axial Pumps . . . . . . . . . . . . . . . . . . . . 31
10 Advantages and limitations of Twin Screw Pumps . . . . . . . . . . . . . . . . . . . . 32
11 Field application of Multiphase pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
12 Equipment specification data (Wellhead Desander Halliburton) . . . . . . . . . . . . . 38
13 Technical Specifications of a Coarse Filter . . . . . . . . . . . . . . . . . . . . . . . . . 43
14 Balmoral Oil Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
15 Balmoral Reservoir Fluid Composition . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
16 Matrix analysis approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
17 Separator Matrix Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
18 Operating Parameters of Balmora Field . . . . . . . . . . . . . . . . . . . . . . . . . . 74
19 Table with the separator sizing for 21000bpd production rate . . . . . . . . . . . . . . 75
20 Comparaison between Exclusionary techniques and Inclusionary techniques . . . . . . 84
21 Advantages and Disadvantages of Topside and Subsea Treatment . . . . . . . . . . . . 89
22 Advantages and Disadvantages of Disposal solutions . . . . . . . . . . . . . . . . . . . 91
23 Single-Phase Centrifugal Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

11. Abbreviations
API: American Petroleum Institute
Bpd: B/D Barrels produced per day
BHP: Bore Hole Pressure
BOPD: Barrel of oil produced per day
CAPEX: Capital Expenditure
CEC: Compact Electrostatic Coalescer
CD: Drag Coefficient
CFU: Compact Flotation Unit
CTAGC: constant of gas capacity process
CTALC: constant of the liquid capacity process
DSV: Diving Supply Vessel
DM: Diameter
Di: Internal diameter
E: Joint Efficiency
Ep: Pump Energy
ESP Electrical: Submersible Pump
FW: Expected water cut
GLCC: Gas-Liquid Cylindrical Cyclone
GoM: Gulf of Mexico
GOR: Gas Oil Ratio
GVF: Gas Volume Factor
HAP: Helico-Axial Pump
HO: Oil thickness
IFP: French Institute of Petroleum
K: Sounders and Brown Constant
Lss: Total length
LEFF: Effective length
mD: Millidarcy
Mm: millimetres
MMSM3/D: Million Standard Cubic Meter per day
MW: Mega Watt
MMBOPD: Million Barrel of Oil produced per day
Mpa: Megapascal
NFA: Net Free Area
n: number of moles
OPEX: Operational Expenditure
OTC: Offshore Technical Conference
OiW: Oil in Water
P: pressure
PFL: Pressure loss due to friction
PEH: Pressure loss due to elevation Head
PPR: pseudo-reduced pressure
PCP: Progressive Cavity Pump
PFR: Pump Inlet Flow Rate Pressure
Psi: pounds per square inch
PPM: Parts per Million
PVT: Pressure Volume Temperature
Ppmv: Parts per million by volume
QI: Flow rate
QG: Gas Flow rate

12. QW: Water Flow Rate
QO: Oil Water Rate
R: Ideal Gas Constant
RE: Reynolds number
ROV: Remotely Operated Vehicle
RDP: Roto-Dynamic Pumps
Rev/min: Revolution per minute
SCF: Standard Cubic Feet
STB: Stock Tank Barrel
S: Maximum Tension
SESV: Subsea Equipment Support Vessels
SG: Specific Gravity
ST: Total SECTION
SW: Water Section
SWIT: Seawater Injection and Treatment
T: temperature
TA: Axial Thickness
TD: Design Thickness
TSP: Twin Screw Pump
TPH: Total Petroleum Hydrocarbon
TPR: Pseudo-Reduced Temperature
TR: Retention Time
TRW: Water Retention Time
TRO: Oil retention time
TR: Radial Thickness
TSS: Semi Spherical Thickness
UV: Ultraviolet
V: Volume
VT: Settling Velocity
VSEP: Volume of separator
VBODY: Body Volume of Separator
VTAP: Tap Volume of Separator
VASP: Vertical Annular Separation and Pumping System
WC: Water Cut
WHD: Wellhead Desander
WSEP: Weight of separator
Z: Gas compressibility factor
α: Constant
ρg: Gas density
ρl: Liquid density
η: Pump Efficiency
µg: Gas Viscosity
µm: Micron
∆p: Pressure differential
∆γ: Viscosity differential
3-PGS: 3 Phase Gravity Separator
2-PGS: 2 Phase Gravity Separator

13. 1 Project Introduction
1.1 Background of Work
Many topside processing facilities are currently capacity constrained due to the volume of produced
water that requires treatment at the topside. This is backing out potential oil production from other
satellite discoveries that could have been tied back to existing offshore platform; and thus reducing
the amount of produced water requiring topside treatment would increase oil handling capacities of
such offshore platforms.
There are strong indications that several offshore oil and gas fields are maturing and have already
or almost passed their production plateau. Several of these fields have now reached their production
peak with reservoir pressures declining and their natural drive insufficient to maintain the original
production levels. Countering this trend leads to the critical point when a decision arises as to when
fields must either be abandoned or some form of additional pressure boosting provided in order to
enhance recovery from these ageing fields.
Decommissioning offshore infrastructures from these fields could be very costly and the rounding
existing marginal field may never be produced. It is of interest to both the operators and government
to maximise reserve recovery and tieback close by marginal fields. One way to debottleneck top-
side facilities and increase hydrocarbon production from both existing and new fields is through the
application of subsea processing system. Subsea processing, also known as seabed processing refers
to the treatment of produced hydrocarbon on the seabed, in order to reduce the amount of topside
processing, enhance reservoir oil recovery and also reducing flow assurance challenges before getting
to the topside or onshore facilities. It also encompasses a number of different procedures to assist
in reducing the capital expenditure, operating cost and complications of setting up an offshore field.
Subsea processing technologies now provides tremendous solutions to offshore oil and gas production
which before now has been major challenge. This project therefore tries to address the challenge of
high amount of water cut from Brownfields using subsea processing system.
1.2 Why Subsea Processing ?
Subsea processing has huge tendency of optimising recovery by water/gas injection and also reduces
development cost by transferring some of the traditional topside fluid processing to the seabed.
In addition, it saves space on topside facilities, as water separation and sand treatment processes
can be carried out on the seabed, debottlenecking the processing capacity of the topside facility. By
removing undesirable constituent of production at the seafloor, required transportation through flow
lines and risers to the facility on the water’s surface for further reinjection is avoided. As shown in
the figure below.
1

14. Figure 1 – Subsea Processing (Source:FMC)
The key advantages of subsea processing are discussed briefly below.
Improved Reservoir Productivity: A fundamental benefit of seabed processing (separation and
liquid pumping) is improvement in pressure drawdown as a result of reduction in back pressure and
increase in reservoir pressure through water reinjection. This results in increase in production rates
and improved oil and gas recovery. The use of a Single Phase pump overwhelms the static back-
pressure of the fluid column along the production line from the seafloor to the surface, while also
avoiding it avoids undue pressure drops and upsurge of multiphase flow.
Deepwater and Long-Distance Tiebacks: Subsea separation and liquid pumping allows easy
flow of produced and processed hydrocarbon over a long step out distance, and in deep water applica-
tion. This is as a result of the transportation of produced fluid by a mechanical means (use of pump)
rather than full dependent on reservoir pressure for pumping. Subsea liquid pumps are currently
available for most applications, while separator gas can flow long distances under natural pressure.
As large capacity production advances are made, subsea power supply and compressor systems, sub-
sea gas compression becomes a viable option, allowing reduced pipeline size and even longer transport
distances.
Flow Assurance: Subsea processing can provide a cost resolution to flow assurance related chal-
lenges. The subsea processing system in the figure below shows that the different phases of the well
stream is separated and conveyed in different pipelines, to eliminate multiphase flow and related
problems. Although the separated gas entering the flow line is saturated with water, which still raises
the concern of hydrate formation, the volume of water can however be very much predictable, and
too little to trigger hydrate formation. It also disqualifies the need to over inject inhibitor to mitigate
water slug, which is naturally avoided when liquid and gas flows in different flow lines, so as to allow
the use of the more environmentally friendly inhibitor like glycol that can be readily recovered and
regenerated at the host platform.
2

15. Figure 2 – Subsea separation and pumping
Topside Facilities Limitations: Produced fluid gets to the platform facilities already processed
and separated into various phase in the case of subsea processing which reduces the need for large
slug catchers and separators. Degassed oil and water can go through subsequent separations on the
seabed with the produced water re-injected back to boost production, thus eliminating the need for
surface water treatment with a reasonable reduction in overall power requirement.
Unmanned, Safe and Minimum Facilities Developments: Aside the primary benefit of im-
proved productivity and recovery, subsea processing also ensures oil and gas development with mini-
mum production enables huge reduction in personnel requirement for operations. It ensures increased
safety of personnel and environment as the facility is located far from the personnel. [Choi and Wein-
garten, 2007]
1.3 History and Evolution of Subsea Processing
Subsea processing has been the subject of much research and development for many years. In this
context, the word “processing” is usually used to cover separation of sand, oil, water and gas, pump-
ing, compression or any combination of these. However, despite all of this work and a number of
pilot projects in recent years, subsea processing has not yet become a routine operation. A number of
building blocks have been demonstrated in the past with varying success. There remains much work
to be done and indeed, there are technology gaps yet to be filled.
Since 1970, development of subsea separation and pumping systems has resulted in massive capi-
tal investments, with lots of unresolved issues as a result of lack of clear understanding of the cost
benefits of subsea developments, which led to an obvious lack of confidence and complete reluctance
in carrying out a full commercial deployment of the technology.
The maiden step into conventional subsea processing originated from of subsea pumping system,
having backpressure reduction as the main focus. The trend however moved from the stand alone
pumping system to a more advanced separation and pumping operation. Gas and liquids separation
takes place subsea, with the gas (due to its natural tendency to flow on its own) flowing naturally and
3

16. liquids pumped to surface in order to reduce the back pressures and optimise production efficiency.
The subsea separation activity which was initially in form of primary separation, soon evolved into
secondary separation, with further water treatment and injection. In order to continue this giant
stride, gas compression also became an additional subsea processing operation to carry out seabed
gas compression which reduces backpressure on the reservoir and prevents slugging.
Figure 3 – Evolution of Seafloor well technology
The subsea separation and processing system has long been the major desire of upstream engineers
and operators, this technology though relatively new and yet to gain wide acceptance has experienced
tremendous improvements. This dream was realised in 2007, with the successful startup of the FMC
technology operated subsea separation, boosting and injection system on Statoils’ Tordis field in the
North Sea. This installation popularly regarded as the first full-field subsea processing system, en-
sured an increase in recovery by about 35MMBOPD and also extending the field life by 15 to 17 years.
Before the Tordis installations, operators only regard subsea processing as just a form of artificial
lift method for subsea developments. However, with a more refined outlook to the technique, result-
ing in both Green and more importantly Brownfield applications to reduce topside processing, it has
led to an increased drive in the usage of the technology. Future field developments can also gain
from the application of subsea separation technology to reduce required topside processing facility
and by extension saving more on production platform costs while also improving profits on subsea
wells (which holds a predicted 400-500 increase in number of wells coming on stream from the year
2011 [Howard, 2007].
Subsea processing can be key to operators’ project economics from startup of Greenfields. Lower
tertiary fields mostly found in the Gulf of Mexico, with heavy oil and poor rock reservoirs, have
benefited from initial installation of subsea separation and pumping systems before commissioning.
These options are forms a major part of the field development plan. Having the systems in place
before the first oil can help the operator maintain production at a higher level for a longer period.
Another case of the usage of subsea processing system is in remote or harsh regions, where field
development options with surface facilities can be limited. In such cases, with more robust and so-
phisticated subsea processing technologies, it is more likely to see full field development done subsea.
A typical example is in the arctic regions where operator may not have the option to construct a
surface facility [Perry and Rega, 2011].
The following shows a summary of some subsea processing technologies employed till recent time:
4

17. ˆ Zakum Subsea Process System 1969, OTC 1083
ˆ GoM Submerged Processing System 1975
ˆ Highlander Subsea Slug Catcher 1985
ˆ BOET Argyll Subsea Separator 1988, OTC 5922; 1990 OTC 6423
ˆ GA-SP Goodfellows Statoil 1991 carried into Alpha Thames work
ˆ Kvaerner Subsea Booster Station 1992
ˆ GLASS Bardex 1993 OTC 7245
ˆ VASPs Petrobras 1990 – 1998
ˆ DEEPSEP MAI & Petrobras 1995
ˆ ABB COSWAS 1997 – 2001
Table 1 – Recent Subsea Processing and boosting installations
The rapid growth in subsea production systems was mainly driven by major deep-water developments
and the need for cost effective production of marginal offshore fields. However, there is also increasing
interest in extending the subsea tieback distance boundaries as well. “Subsea to Beach” developments,
such as West Delta Deep offshore Egypt and Ormen Lange offshore Norway which have the additional
advantage of requiring no personnel permanently based offshore, giving both safety, and cost benefits.
5

18. Figure 4 – Major Subsea Processing Projects
The Petrobras Marlim (2011) located in Brazil uses a 3-phase separation and water injection system.
The water depth is about 900 metres, with a step out of about 5 Kilometres. The processing capac-
ity of 22,000 bpd achieved a water cut of 67%. The project also made use of compact separators for
de-oiling and de-sanding, alongside a water injection pump (1.9 MW/∆p 180 bar, OiW100 PPM). Ma-
jor challenges solved for this project were high viscosity, sand production, reduced water production.
Considering the Petrobras’ Marlin project, which was one of the world’s first pilot system for deep-
water subsea separation of heavy oil and water, it includes a reinjection of produced water to optimise
production in a mature field development. The system is aimed towards improving production, em-
ploying the same topside facilities, or to completely replace the topside equipment. The field architec-
ture maybe redesigned to incorporate more subsea separators to address existing wells. This improved
field production life without adding different topside facilities, and thereby improving revenue with
the existing wells and floating units.
The world’s first gas/liquid separation and boosting system, on Shells’ BC-10 project (offshore Brazil),
which was developed to operate over 13 subsea wells, with six subsea separators and boosters began
producing heavy oil from ultra-deep waters in July 2009. The Shell Perdido project in the Gulf of
Mexico also incorporates a subsea boosting and separation system, with same aim of achieving pro-
duction.
On the 5th of September 2011, the first application of the subsea processing system in the West
Africa region was recorded on Total’s Pazflor offshore project with a water depth between 800-900
metres, a step out distance of 14 kilometers and a processing capacity of 110,000 BOPD and 1.0
MMSM3/D utilizing a gas tolerant pump (Hybrid to 15% GVF, X 2.3 MW max Ap 180 bar). This
innovation was able to address the high viscosity and stable emulsion challenge. Large pressure drop
in flowlines and risers where improved alongside the large amounts of methanol needed to hydrate
prevention.
1.4 Major Suppliers of Subsea technologies
There are quite a few suppliers of subsea processing equipment already existing in the oil and gas
market. The Leading suppliers of this innovative solution includes Cameron, OneSubsea., FMC
Technologies, GE Oil & Gas, Subsea 7, Technip, Expro, Intecsea and Foster Wheeler.
6

19. 1.5 Project Aim
The aim of this project is to develop a low cost subsea processing system and can be employed
in brownfields to cut down the amount of produced water transported to topside, and identify the
equipment building blocks of the system and performing a detailed design of the equipments.
1.6 Project Scope
The scope of this project includes the identification of possible subsea processing system configura-
tions, and also identify technologies available and equipment building blocks for each of the identified
subsea processing system. With an analysis of the identified options and a detail design of the pro-
posed low cost subsea separation system.
1.7 Project Methodology
In order to objectively achieve the aim of the project, several fields currently employing subsea pro-
cessing were thoroughly reviewed. These include Statoil Tordis field, Total Pazflor field, Petrobras
Marlim field, Troll and Balmoral field. Existing technologies from providers such as FMC technolo-
gies, One Subsea, Cameron, Aker Solutions, GE and the technology they provide were reviewed and
assessed.
Then different technical proposals suitable for relatively low cost subsea processing for brownfields
were developed and assess based on their advantages and limitations; and an optimal subsea process-
ing system established. Finally, the different equipment building blocks in the chosen low cost subsea
processing system were discussed.
1.8 Concepts Design Philosophy
The configuration concepts are based upon existing, proven and readily obtainable components and
technologies. The following design philosophies have been adopted in order to meet the project design
objectives:
ˆ All components must be field proven in similar applications.
ˆ All key components must be available “off the shelf”, preferably from more than one supplier.
ˆ Design must minimize the number of “active” component. i.e. minimize the number of compo-
nents which may require maintenance.
ˆ All “active” component to be maintainable from a small to medium sized Diving Supply Vessel
(DSV).
ˆ Minimize life-cycle costs by reducing the need and frequency of intervention.
7

20. 2 System Configuration
The configuration of the subsea separating system is critical to the overall effectiveness and cost of
a subsea processing system. For this project, two options have been taken into consideration and
assessed to establish an optimum configuration for a brownfield development in terms of cost and
field reservoir characteristics.
The two subsea processing system configuration options considered are:
ˆ Two Production Lines, One Injection Line
ˆ One Production Line, One Injection Line
This chapter analyses two different configuration options for a subsea processing system, their equip-
ment building block, merit and demerit of the configuration, the suitability of the configuration to
a mature brownfield development in terms of cost and function (to reduce the amount produce wa-
ter transported to topside); and finally, a selection criteria established to choose the optimal subsea
processing system for brownfield development.
2.1 Technical Option One
Figure 5 – Subsea processing system configuration showing the equipments building block with one
production line and one topside water re-injection line.
The system equipments blocking block for this technical option one are:
ˆ Separator
ˆ Oil pressure boosting pump, and
ˆ Water injection pump.
Produced reservoir fluid coming from the wellhead enters the separator, where the fluid is separated
8

21. into its gas, oil and water component. The separated components are then taken out of the separator
from different outlet. The efficiency of the separation is discussed further under separator design in
the next chapter.
The produced gas is again introduced back into the oil flow and boosted together to topside via
the production line. The existing topside injection is comingled with the separated produced water,
and reinjected to maintain reservoir pressure and enhance hydrocarbon recovery.
It is assumed; and this is correct most of the time, that before the implementation of this option
the brownfield already has installed a single production line that is been used for the transportation
of the untreated produced reservoir fluid (gas, oil and water) and a water injection line used for
maintaining pressure. Hence, in implementing this option no new additional riser line; which could
otherwise lead to a very substantial cost, needs to be installed as only the existing the production
line and water injection line is needed to implement this option. A short fall of this option is that the
introduction of gas in the oil line could lead to slugging.
2.2 Technical Option Two
Figure 6 – Subsea processing system configuration showing the equipments building blockwith two
production line and one topside water re-injection line.
The system equipments blocking block for this technical option one are:
ˆ Separator
ˆ Oil pressure boosting pump
ˆ Water injection pump, and
ˆ Gas compressor
The system configuration shown above in figure 6 is similar to that of option one except that two
production lines are employed (an oil production line and a gas production line) and a gas compressor
is added. This is to enable the separated gas and oil to be separated to topside independently and
9

22. thus avoid the problem of slugging. This option is more feasible if the amount of gas produced from
the reservoir is large.
The major short fall of this option is the cost involved in installation of a new additional riser
line and the cost of the additional equipment – subsea gas compressor. Like it has been explained
above, it is assumed that only two riser lines already exist in the brownfield, hence a new riser line
need to be installed if the gas is to be transported to the topside independently.
2.3 Selection of the Low Cost Subsea Processing System Configuration
The separation of gas, water and oil and adequate sand management sand is a great benefit of subsea
processing, resulting in increased production and improved way of handling flow assurance challenges.
Although the subsea processing system configurations shown by both options one and two captures
most of the benefits of subsea processing operations, like reducing back pressure, and eliminating
multiphase flow assurance challenges. Considering the low cost approach to this project, the choice
of the subsea processing system configuration has been based on the suitability of the configuration
to brownfield development in terms of cost and function (to reduce the amount produce water trans-
ported to topside).
The table 2 below shows a comparison of the merit and demerit of the two different subsea pro-
cessing system configuration considered, and that it forms a basis for the justification of the option
selected.
Table 2 – Comparison between the identified low cost subsea processing system configuration options.
From the analyses of the merit and demerit of the options, option one (one production line and one
water injection line) is the optimal subsea processing system configuration for brownfield development.
In the next chapter, a detail description and design has been done of each of the equipment building
blocks as outline in the chosen configuration option.
10

23. 3 Subsea Processing Technologies
3.1 Subsea Separators and Technologies
Separators are a major building blocks of a Subsea Separation System used primarily to breakdown
and separate various product composition from a reservoir. Operators choose many reasons for in-
stalling subsea processing equipment. Subsea separation and processing system will enhance the
hydrocarbon recovery from the field and water cut, especially in the case of a brownfields, thus in-
creasing profits.
A mixture is considered heterogeneous, if it consists of two or more phases with different compo-
sitions. Under careful observations, it is possible to see visible boundaries of separation between the
various constituents of the mixture. Compounds and elements may be the building block of these
substances. The components and composition of the mixture can be separated by considering an
appropriate and suitable technique [Viska and Karl, 2011].
An approach that exploits the basics of physics for use in the difference in density between the
phases of the composition is very useful. The simplified classification of the likely phase separation
are:
ˆ Liquid – Solid
ˆ Solid – Solid
ˆ Gas – Solid (Vapour – Solid)
ˆ Liquid – Liquid (Immiscible)
ˆ Gas – Liquid (Vapour – liquid)
Subsea separator refers to equipment used in separating different phase compositions of produced
hydrocarbon on the seabed. They convert marginal fields into economically viable developments used
to debottleneck on topside processing facilities. The choice of a subsea separator type depends mainly
on the aim and objective of the separation to be made, fluid composition, depth of operation and
expected flow assurance problems.
Figure 7 – subsea separator showing the input and output layout.
11

24. The main types of subsea separators are as follows:
ˆ Gravity Separator
ˆ Compact and Dynamic Separators
ˆ Semi Compact Gravity Separation System
ˆ Caisson Separation System
3.1.1 Gravity Separator
Subsea gravity-based separators (which are most widely separators in the oil and gas industry) op-
erates on the principle of specific gravity differences of fluid composition to be separated. As shown
in the figure below, the lighter fluid phase rises at certain rate which is dependent on the droplet
diameter and fluid viscosity [DAIGLE et al., 2012]. Oil droplets with smaller diameter rises slowly
and if the retention time of the separator is not sufficient, the water will exit the separator before the
small droplets of oil rises through the water to form an oil layer.
Figure 8 – Ensepatec 3-phase separator: http://www.ensepatec.com/en/products/process-
internals/three-phase-separator-2.html, Accessed March 2015.
Gravity-based separators are useful for the first line of a hydrocarbon separation. They are designed
to ensure complete separation of gas in free water. Gases are mechanically withdrawn as a floating
phase, with oil occupying the intermediate column and water settling to the lower part of the vessel.
The gravity-based separator can be configured both horizontally and vertically.
Vertical separators are used to separate fluids that are predominantly gaseous in composition. They
are an ideal choice for separating fluids with more gas because gases require a larger coalescing area,
which is offered by the longer distance in the vertical direction.
12

25. Figure 9 – Three Phase Vertical Gravity Separator [Mulyandasari, 2011])
However, horizontal separators are ideal for separating fluids, which consists of mainly liquid. The
quality of liquid / liquid separation depends on the retention time of the separator, which is a func-
tion of the separator length and diameter. Hence, the longer a separator, the higher the retention or
settling time and by extension, the higher the efficiency.
The gravity-based separator performs to about 50% to 90% efficiency in the removal of free oil
above 150µ. However, the major downside to the usage of gravity-based separator is that soluble
components of the total petroleum hydrocarbon (TPH) are not efficiently removed with the process.
It is recommended free oil concentration in the range of 15 -100ppm [DAIGLE et al., 2012].
Figure 10 – Three Phase Horizontal Gravity Separator [Mulyandasari, 2011])
Asides the vertical or horizontal orientation classification of gravity-based separators; it can also be
classified as either two or three phase. A two-phase separator is used for liquid / liquid or gas / liquid
separation, while the three-phase separator is used to separate gas, oil and water.
13

26. Table 3 – Advantages and disadvantages of horizontal and vertical separators
3.1.1.1 Design Considerations
The design of the vessel internals could fundamentally influence the working performance of a sepa-
rator through it drop / bubble shearing and blending, foam creation, distribution, mixture and level
control. A major factor to be considered for design of a separator is the settling hypothesis or re-
tention time for its liquid holding column. Separators are designed with sufficient margin to handle
liquid surges or production changes regularly experienced amidst production. They have the following
functional zones deliberately designed to produce and attain its required performance.
ˆ Inlet zone
ˆ Flow distribution zone
ˆ Gravity separation / Coalescing zone
ˆ Outlet zone
Inlet Zone
The inlet zone takes care of the initial bulk separation of the oil (liquid) and gas, removing most
of the gas from the liquid. The gas separation would be effected as the pipe leads it into the separator
because of a drop in pressure across a control valve or upstream choke. Cyclones are now being
considered in the inlet design to address foaming issues and high capacities handling. Flat impact
plates, dished-head plates, half-open pipes, vane-type inlet and cyclone-cluster inlet are examples of
typical inlets.
These aforementioned inlet types, though inexpensive, often affects separation performance, as inlet
selections may pose a huge challenge for fluids with higher momentum. Foams and small drops may
occur when a dished-head or flat head plate are used [Wally, 2013].
Flow Distribution Zone
A poor separation efficiency may result from short-circuiting irrespective of the size of the sepa-
rator vessel. An important addition and consideration to the inlet is flow straightener, which may be
14

27. a single perforated baffle plate. The uniform flow of the gas and liquid after it leaves the inlet (cy-
clones, impact plates, or vane-type inlet) is solely dependent on the diameter of the plate. The bigger
the plate, which also doubles as a foam breaker and an impingement demister, the more uniform the
flow [Heijckers, 2012].
The net-free area (NFA) which is between a range of 10 to 50% when lowered leads to a higher
fluid shear, so that it can match a particular application. A major concern is the solid build-up that
occurs on the upstream side of the plates. The inlet velocity is enough to move the solids through
the perforations. A flush nozzle installed in the inlet zone will likewise aid its proficiency.
Gravity/ Coalescing Zone
The internal of a gas / liquid gravity separator is sometimes fitted with plate / matrix packs, mesh
pad, and vane pack to aid separation and foam breaking. These internals help enhance coalescing
effect of the dispersed phase by providing a better impingement or searing surface. In a gas phase,
liquid drop coalescence or foam breaking can be attained by utilising the matrix / plate packs and
vanes. The principle of installation of the high surface internals like the plate packs for foam breaking
is so bubbles stretches and break as they drag across surfaces. Be that as it may, if the bulk of the
gas flows through the top portion of the pack, the foamy layer will not be sufficiently sheared, and
the bobbles will meander through to the other end
Outlet Zone
All mist elimination equipment can be classified as cyclones, fibre-beds, mesh and vanes. The cap¬ture
of mist can happen by three mechanisms; it is noteworthy, that there are no clear limitation between
systems. The droplet momentum varies directly with liquid density and the diameter of the cube,
heavier or larger particles tend to resist following the streamline of a flowing gas and will strike objects
placed in their line of travel.
The mechanism in charge of removing most particles of diameter > 10µm is termed inertial im-
paction. Direction impact defines a situation when particles with smaller diameter that follows the
streamlines collide with the solid objects, if their distance of approach is less than their radius. It
is frequently the governing mechanism for droplets in the 1 to 10µm range. With submicron mists,
Brow¬nian capture becomes the predominant collection mechanism. This relies on Brownian motion:
the unbroken random motion of droplets in elastic collision with gas molecules. As the particles
become smaller and the velocity gets reduced, the Brownian capture becomes more efficient.
3.1.1.2 Performance Impediments
Foaming (froth) happens, when there is a pressure reduction on some reservoir oil types, leading
to the dispersion of tiny bubbles of gas that are encased in a thin film of oil are dispersed when
the gas is liberated from the solution. For some other crude oil types, the oil viscosity and surface
tension may mechanically hold gas in the oil and may lead to a similar impact to foam. Oil foam
is not particularly steady or durable except in the presence of a foaming agent in the oil. Organic
acids are the major foaming agent, while high-gravity oils and condensates do not result in foaming
situations [Callaghan et al., 1985].
The ability of an oil / gas separator is reduced by foaming, needing a higher retention time for
proper separation of a given quantity of foaming crude oil. It is difficult to measure with conventional
volumetric metering vessels or a positive-displacement foaming crude oil. It leads to loss of oil and
gas as such special equipment and procedures are required in handling such challenges. The under
listed factors assist in breaking / reducing foaming and to eliminate entrained gas from the oil:
15

28. The under listed factors assist in breaking / reducing foaming and to eliminate entrained gas from
the oil:
ˆ Agitation (baffling)
ˆ Centrifugal force
ˆ Chemicals
ˆ Heat
ˆ Settling
Table 4 – Internal Devices and Separation Aids for Separators
3.1.2 Compact and Dynamic Separator
The installation and maintenance of the traditional gravity based separator poses a huge challenge for
deep-water applications. The focus of the offshore industry was channelled into a research programme
to seek alternative technologies that could meet requirement for deep-water application; this led to
the development of compact and dynamic separators.
The main driver behind manufacturing compact separator is to improve project economics or re-
duce project cost especially in deep water. Using large gravity based separator for deep water affects
overall cost of subsea station [SPE, 2012]. This is because the prospect of retrieving separators for
repairs in deep water is completely remote.
The available technology of compact separator varies, a few of which are explained below:
ˆ Cyclonic Separators
ˆ Hydrocyclone
ˆ Compact Electrostatic Coalescer system- Aker Solution
ˆ In-line or Pipe Separators
16

29. 3.1.2.1 Cyclonic Separators
Cyclonic separators are used in the oil and gas industry for separating particulates from gas or liquid
stream, without using any filter through vortex separation. This technology utilises the principle of
rotational impact and gravity to separate mixtures of solids and fluids. Additionally, it can also be
used in separating fine droplets of liquid from a gaseous stream.
A typical cyclone is made up of an inlet, two outlets for the separated fluids and a cylindrical body
where a swirl is created, which then introduces centrifugal forces on the fluid stream as shown in
the figure below. The centrifugal force is several times the gravitational forces [Slettebø, 2009]. Due
to differences in density, the liquid will travel outward forming the outer vortex and moving in a
downward direction. The gas on the other hand moves inward and form the inner vortex and travels
in the upward direction towards the gas outlet.
Although the cyclonic separator offers a system of separation at low cost and easy retrieval, their
designs are very complicated when compared to the simple gravity settling systems, with potentially
expensive operating cost because of their eroded parts which can easily experience failure. Despite
its limitations with respect to cost, their removal efficiency is preferable when compared to that of
the gravity separators especially when used for smaller particle sizes.
Figure 11 – Typical Cyclonic Separator [BENAVIDES, 2012]
The Gas-Liquid Cylindrical Cyclone (GLCC) below was an outcome of a joint research by Chevron
and Tulsa University [Slettebø, 2009]. Its main feature is the downward-tilted inlet, with the main
aim of forcing the liquid level below the inlet zone, to reduce the carryover of liquid into gas stream.
The carryover of liquid to the gas stream which would have been experienced with a horizontal inlet
prevents stratification and hence a pre-separation in the pipe. The gas and liquid outlet on the other
hand are made of horizontal pipes.
17

30. Figure 12 – Gas Liquid Cylindrical Cyclone [Slettebø, 2009]
Below is another type of cyclonic separator, the Compact Cyclonic Degasser, which was developed
by Aker Solution.
Figure 13 – Compact Cyclonic Degasser [Slettebø, 2009]
Figure 14 – Hydrocyclone Separator
18

31. 3.1.2.2 Hydrocyclone Separator
A gas cyclone is the type of cyclone used for separating gas, the term Hydrocyclone however refers
to a cyclonic separator used for separating either of solids, or liquids from a liquid [Husveg et al.,
2009]. The hydrocyclone separator is used mainly to separate a two-phase composition of either gas
/ liquid, liquid / liquid or liquid / solid. It uses an induced cyclonic rotation to force the heavier
particle of the mixed phase in one direction while forcing the lighter phase in the opposite direction.
The heavier phase moves outwards and leaves the lighter one to remain in the middle section. It has
an inlet or entrance, a body and two exists. The design in most cases includes the rotational flow or
cyclonic motion [Osvaldo Zuniga, 2013].
The Hydrocyclone, cylindrically constructed, is fitted with more than one inlet that causes fluid
entering into it follow a circular path on the wall. By the rotation of the fluid, a centripetal ac-
celeration field, thousands of times larger that of the earth’s gravity when generated causes heavier
water and solids to move towards the outer wall while causing the lighter material to move to the
centre. By establishing a conical or cylindrical container also referred to as a cyclone, a very high
speed rotating flow established is the basis of operation of the hydrocyclone. The rotation or spinning
motion generates strong centrifugal forces. This in turn causes air to flow in a helical array, beginning
at the wide end, which is the upper part of the cyclone and it ends at the narrow end, which is the
bottom before the liquid exits the system in a straight stream through the centre of the cyclone and
out at the top.
The hydrocyclone when used for pre-treatment is a bulk separator for large concentrations of gas,
hydrocarbons, and solids in the wastewater stream. The separator helps to remove oil droplets and
solid particles greater than 100 microns in size, which yields a 90% removal efficiency. For primary
treatment, the vessel is designed to remove all droplets of oil and remove particles containing solids
of sizes greater than 35% microns. A significant amount of emulsified oil and suspended solids are
effluent of the primary treatment. A downstream secondary treatment can help to eradicate the
suspended solids and emulsified oils. The hydrocyclone removes particle within the range of 5-15
microns, and does not remove soluble oil or grease.
Standard Dimension of a Cyclone
During the design of cyclones, good consideration of previous working standards were adopted to
define how varying dimensions of cyclones would affect its performance. A typical example still used
today is a design standard by Shepherd and Lapple (1939 and 1940), who determined the “opti-
mal” dimensions for cyclones. Succeeding investigators testified similar work result as such; cyclones
“standard” became adopted.
19

32. Figure 15 – Sketches of a reverse-flow, cylinder-on-cone cyclone with a tangential inlet
The geometrical notations indicated in the right sketch are:
a – Inlet height
b – Inlet width
h – Height of cylindrical section
hc – Height of conical section
D – Body diameter (barrel diameter)
Ht – total height of the cyclone (roof to dust exit)
Dx – Vortex finder diameter
S – Vortex finder length (roof to separation space)
Bc – Cone-tip diameter (dust exit diameter)
The table below shows dimensions related to the cyclone’s body diameter. It recapitulates the dimen-
sions of standard cyclones of the three different types, with the highlighted option the most adopted.
The selection of other options depends on the target objective of the separation process.
Table 5 – Dimension of Standard Cyclone, Columns (1) and (5) = Stairmand, 1951; Columns (2), (4)
and (6) = Swift, 1969; Column (3) and sketch = Lapple, 1951
Primarily, a hydrocyclone is an economical and recognised technique with little or no moving parts
in this device, which makes its fabrication easier. Depending on the intended usage, hydrocyclones
20

33. allow manufacture size more compact whereby they take little or no space topside or subsea. Recent
innovations now allow the possibility to place hydrocyclones in multiples next to each other either in
a parallel, in a series or both combination set-up.
3.1.2.3 Compact Electrostatic Coalescer (CEC)
This small lightweight flow-through system, which was developed by Aker Solution, greatly im-
proves the efficiency of separation by existing downstream gravity separation equipment. This is
can be achieved by coalescing emulsified water droplets caught in the crude oil into much larger
droplets [AkerSolution, 2015]. The coalescing action takes place very rapidly under turbulent flow
conditions as the emulsion is subjected to an intense electrostatic field.
In addition to reducing space and weight requirements, the CEC provides a proven efficiency level
when debottlenecking. If an existing separator is being modified without any alteration in its existing
installations, a compact electrostatic coalescer may also be considered.
Figure 16 – Compact Electrostatic Coalescer (CEC)
3.1.2.4 In-line or Pipe Separators
In line or pipe separators involves the use of cyclones in the pipelines, in order to effect separations.
Below are different types of inline separators.
ˆ Dewaterer: This is used to remove water from oil stream. It can be used as the second line of
separation after the gas / liquid cyclone, in a train of separation made of mainly cyclones
ˆ Inline Phase Splitter: It is used to split the flow in a gas volume fraction between 10% and
90%. Usually, it takes care of the first stage separation before some finer separation is done to
the separated flow. It enables separation of two uniform phases.
ˆ Inline Degasser: It removes gas from a liquid stream. The gas outlet includes a second stage
separator system for the removal of liquid droplets that were entrained in the gas.
ˆ Inline Deliquidiser: This is used to separate liquid from a gas stream. The liquid outlet
includes a second stage separator system for removing of bubbles of gas that followed the liquid.
ˆ Inline Electrostatic Coalescer: Like the CEC, it increase the size of water bubble in oil.
ˆ Inline Demister: A bundle of small diameter demisting cyclones (Spiral flow) in a pipe spool.
ˆ Bulk Deoiler: Separates oil from water stream.
21

34. ˆ Desander: Used to separate solid from gas and liquid or multiphase stream.
Table 6 – Comparison of In-line or Pipe Separators
The figures below shows the various types of inline separators.
Figure 17 – Schematics of Inline Cyclonic Units: Phase Splitter (Left), Deliquidizer (Middle) and
Degasser (Right) [SPE, 2012]
22

35. Figure 18 – Inline Cyclonic Separation Equipment: Liquid/Liquid Separator (Top Left), Phase Splitter
(Top Right), Deliquidiser (Bottom Left), and Desander (Bottom Right)
Although the compact separator reduces the capital cost of a subsea processing project and increase
the ease for the retrieval of a separator, reduction in separator size, it however, comes with an un-
wanted trade off effect with performance. Compact separators, with reduced sizes affects separation
performance and the ability to handle change in flow, and thereby raises serious doubt in its confor-
mance with separation requirement especially when operation is under slugging condition [Hannisdal
et al., 2012].
In effect, the risk for loss in revenue because of poor separation performance is increased compared
to that of the non-compact traditional gravity separator, thereby affecting the overall cost of the
subsea station. In shallow water, the installation can be made easier if the size is within the capacity
of a diver crane. Although the retrieve-ability of a separator is affected by module weight and the
availability of intervention ships, it becomes less of an issue for a gravity separator because of its
usually high reliability and mean time to failure.
3.1.3 Semi Compact Gravity Separation System
It is a system that Incorporates the use of a typical gravity based separator with a Gas-liquid compact
cyclonic at the inlet, hence the name Semi Compact. Gas liquid separation takes place at the inlet
while liquid/liquid Separation takes place in the Gravity vessel. The most common example of the
usage of a semi compact gravity separator is in the case of Tordis’ subsea processing system, assembles
by FMC Technology for Statoil.
Figure 19 – Semi Compact Separator in Statoil’s Tordis Field
23

36. 3.1.4 Caisson Separation System and Vertical Annular Separation and Pumping Sys-
tem (VASP)
The caisson is generally a tall separator that is usually installed in a dummy well. The system has
a tangential inlet to a tall narrow vessel that handles slugs, provides surge volume for the produced
hydrocarbon to be separated, and supports the ESP.
The vertical annular separation and pumping system (VASPS) is another type of separator that is
very much similar to the caisson separator. The VASPS is made up of an internal helix that separates
the pressure housing and the inner gas annulus in the tall separator. The VASP like the Caisson
separator is also installed in a dummy well.
Figure 20 – The Inlet Block of the Caisson Separator Used in the Shell Perdido Field
Caisson Separators are generally more complex than the gravity separators. It comprises the caisson
driven into the seabed, and a cylindrical cyclonic gas liquid separator at the top and an electrical
submersible pump (ESP) located further down inside the caisson. The processes of separation in a
caisson separator is as follows:
ˆ The produced fluid comes into the caisson through the inlet block, which is just above the mud
line and then moves into the separator via a purposefully angled and tangential inlet.
ˆ As the fluid stream flows in downward direction, the spiral designed flow pattern gives rise
to a liquid and gas separation. The separation occurs by a combination of centrifugal and
gravitational force, which throws the heavier liquid or fluid to the wall of the separator
ˆ The separated liquid continues with the downward flow to the caisson sump, where the ESP
pumps it upward.
ˆ The separated gas flows upward due to its own pressure.
3.1.5 Comparison of Separator Technologies
The following table compare separator technologies.
24

37. S/N
SEPARATOR
TYPE
ADVANTAGES DISADVANTAGES
1
Gravity Separator Simple Concept
High Reliability and Mean Time To
Failure
Better Sand Separation From Fluid
Stream with a sand flushing system
Good Separation Efficiency
Tested with success in shallow water
processing
Can be Installed with diver crane
Reduced operating cost because of
reduced level of required intervention
due to little or no repairs
Might not require batch separation
Effective handling of change in flow
Meets oil in water requirements
Performs well in treatment of high Oil
concentration.
About 50-99% efficiency in removal of
free oil particulate above 150µ
More difficult to install than
the compact separator
because of its size
High capital cost
Requires sand flushing or
jetting system as sand
settles at the bottom without
following water
2
Inline or Pipe
Separator
Smaller size, hence more suitable for
higher depth and high design pressure.
Suitable for separating difficult fluid
Not good in handling
change in flow
Overall system still as bulky
as the gravity, with only
diameter reduction#
No recorded test and
success level in shallow
water
Not efficient for one batch
three phase separation
Sand handling is a major
challenge.
Will not handle large slug
except with slug catcher.
3
Cyclonic Separator Smaller size, hence more suitable for
higher depth and high design pressure.
Handle sand easy because it goes out
together with the separated water
Not good in handling
change in flow
No recorded test and
success level in shallow
water
Not efficient for one batch
three phase separation
Challenges with meeting
requirements for both Oil in
water and Water in Oil
Results in large pressure
drop
Requires extra water
treatment technology.
4
Semi Compact
Gravity Separation
System.
More optimal separation compared to
the Gravity separator.
Tested on the Tordis field with recorded
success.
Like the gravity, it is good with sand
treatment.
Handles higher gas flowrates than the
gravity separator.
Separates three-phase in one batch, with
gas separation taking place at the inlet
G/L Cyclone.
Also more difficult to
install, even though it is
more compact than the
gravity separator.
Like the Gravity separator,
requires sand flushing
system.
5
Caisson Separation
System and VASP
Suitable for deep water with recorded
success.
Not effective for high level
of produced sand.
Huge operating cost which
may arise through drilling
of the required dummy well
Retrieval of ESP can be
very challenging.

38. 3.1.6 Technology Manufacturers
ˆ Subsea 7
ˆ Technip
ˆ Cameron
ˆ Saipem
ˆ One Subsea
ˆ Expro
ˆ General Electric Oil & Gas
ˆ Foster wheeler
ˆ FMC Technologies
26

39. 3.2 Subsea Pumping
3.2.1 Single Phase Pump
Historically, single phase pumps have been used by the oil and gas industry and are based on the
following operational principles:
ˆ Positive-displacement pumps: capable of physically moving a volume of fluid from low pressure
to high pressure.
ˆ Roto-dynamic pumps (RDP): transfers kinetic energy to fluids utilizing a rotating impeller and
subsequently transforms the kinetic energy to potential by means of a static diffuser.
ˆ Hydraulic pumps: transfer kinetic energy from high velocity fluid to low pressure fluid.
The single phase pumps are used to boost fluids to the topside, when the gas volume fraction (GVF)
is low, that is if the fluid stream is mainly liquid. However, with the growing needs for multiphase
production, other pump variants were proposed on the basis of single phase pumps concept. French
Institute of Petroleum (IFP) and Total began research into multiphase pumping in the mid-1970s and
limited their work to topside application due to technical requirements in system footprint.
3.2.2 Multiphase Pumping
Subsea multiphase pumping has become the most commonly applied subsea processing technology
and has advanced to become a major oil and gas production tool aimed at increasing the flow of
produced hydrocarbons from a reservoir, to the host facility [Bai and Bai, 2010].
Subsea pumps are used to either inject produced and/or treated water into the reservoir as well
as directly boost produced oil and gas to a host facility.
According to [Schoener, 2004], in the past 15 years multiphase pumps have gained acceptance by the
global oil and gas industry and has thus replaced other conventional production equipment because
of its simplicity, operational flexibility and economic viability. Following its emergence, multiphase
pumping has been beneficial and utilized in offshore fields in the Gulf of Mexico, North Sea, Alaskan
North Slope, Middle East and West Africa. Various pumping systems are available with each tech-
nology possessing its own operational window and application niche which is discussed further in this
chapter.
3.2.2.1 Advantages of Multiphase Pumping Technology
Multiphase pumps for subsea and downhole applications have been available for decades, and has
become a viable solution to a range of field developments. The advantages of multiphase pumping
over other single phase production methods is summarized in the table below.
27

40. Table 7 – Advantages of multiphase pumping
3.2.2.2 Multiphase Pumping Technologies
Today, the leading multiphase pumps designs are classified into two categories, positive displace-
ment and roto-dynamic concept, and certain criteria govern the pump selection based on its intended
application. These pump concepts have been utilized onshore, offshore, downhole and subsea. The
Progressive Cavity Pump (PCP) and Electrical Submersible Pumps (ESP) are used for downhole
applications, while the Twin Screw Pump (TSP) and Helico-Axial Pump (HAP) being the most
commonly used pumps for subsea applications. The figure below illustrates the commercialized and
established pumping technologies available for multiphase fluids. This section focuses on HAPs and
TSPs utilized for subsea applications which falls in line with the project objective, while briefly
explaining the downhole ESP technology.
28

41. Figure 21 – Multiphase Pumping Technologies currently utilized
3.2.2.3 Electrical Submersible Pumps
ESPs are widely used in upstream oil production as an artificial lift method for boosting moder-
ate to high volumes of fluids from a reservoir, a driver module and a pumping unit makes up the ESP
modular. The volumetric flow rate of this pump can vary between 150 and 64,000B/D with pressures
up to 6,000 psi but depends on factors such as gas oil ratio (GOR), bore hole pressure (BHP) and
water cut (WC) [Islam, 2005]. Downhole HAPs which are designed to be a priming device and can
eliminate gas separation, is always connected upstream of a standard ESP, which is used as the main
production device. However, ESPs gas handling capabilities is limited to 75% suction GVF [Hua
et al., 2012] and requires additional gas separation to further handle higher GVF. Similarly, multi-
vane centrifugal pumps can be coupled upstream of a standard ESP to increase its tolerance in gassy
wells. The downhole and surface components of an ESP system is shown in the diagram below, with
the operational benefits and constraints of ESPs summarized in the table below.
29

42. Figure 22 – Schematic of an ESP system Source: Islam, (2005, p.6)
Table 8 – Advantages and limitations of Electrical Submersible Pumps
3.2.2.4 Helico-axial Pumps
The HAP has an operating principle similar to a centrifugal pump whereby rotating impellers in-
creases the fluid kinetic energy and transfers this energy to potential energy by means of static
diffusers. HAPs utilize specifically designed impeller geometry as shown below, which when comin-
gled with a hydraulic channel profile, reduces the radial flow component and results in an axial flow
instead.
30

43. Figure 23 – HAP Compression Stage (Framo Engineering)
Multiphase HAPs till date, used for surface and subsea applications have been manufactured with
impeller diameter ranging from 70mm to 400 mm and normally falls between 3,500 and 6,500 rev/min.
They also cover a flow rate (includes water, oil and gas) at suction conditions between 22,000 to
450,000B/D with a differential pressure up to 2900psi (Hua, 2012). HAPs are widely recognized
to handle suction GVF beyond 90% but in reality this could vary between 0% and 100% making
their range of operating parameters wide. The advantages and constraints in this pump technology
is summarized in the table below.
Table 9 – Advantages and limitations of Helico-axial Pumps
3.2.2.5 Twin Screw Pumps
TSPs have gained predominance in topside heavy oil production and can be dated back to 1934
where it was developed primarily for this purpose. TSPs are available as low pressure pumps up to
45 psi and differential pressures high as 1,450 psi with rotational speed ranging between 600 to 1,800
rev/min but have been reliably run at 3,600 rev/min to attain higher capacities. At suction condition
they can achieve volumetric flow rates (oil, water and gas) from 10,000 to 300,000 B/D depending on
their size [Hua et al., 2012].
TSPs are hydraulically balanced and features two parallel helical screws meshed with each other
and torque is transmitted by timing gears on the end of shafts. The timing gears and drive shafts
in most designs are external to the pumped fluids, timing gears are oil lubricated while shafts could
be oil or grease lubricated in order to improve overall system reliability with heat dissipation. In
31

44. operation, these screws rotate in opposite directions and results in the helical channel of one screw
being periodically obstructed by the other screw. This configuration enables the pumped fluid to
form many small chambers and fill the clearances between one screw’s flange, another screw’s shaft
body and a liner which is displaced during operations shown below.
Figure 24 – Distribution of a TSP Internals
TSPs offer several advantages in certain applications and their operational capabilities can however
be constrained, which is summarized in the table below.
Table 10 – Advantages and limitations of Twin Screw Pumps
3.2.3 Intallation
Multiphase pumps are installed in remote locations from onshore, topside to subsea. Installation of
these packages require unmanned and reliable equipment. SESV (Subsea Equipment Support vessels)
and if necessary, heavy compensation systems utilizing guidelines or guideline-less methods are used
for such operations. The pump module can be installed on mud mats or suction piles/anchor located
at the sea bed. The image below illustrates installation of a pump module with guidelines.
32

45. Figure 25 – Multiphase Pump Module installation by cable
3.2.4 Suppliers/Vendors
The main pump suppliers for HAP, TSP and ESP subsea pump technology applications includes the
following:
Helico Axial Pumps
ˆ Frank Mohn AS (www.framo.com)
ˆ Sulzer (www.sulzer.com)
Twin Screw Pumps
ˆ Bornemann (www.bornemann.com)
ˆ Flowserve (www.flowserve.com)
ˆ GE oil & gas (www.gepowerconversion.com)
ˆ Leistritz (www.leistritz.com)
ˆ Clydeunion (SPX) (www.spx.com)
ˆ Colfax Fluid Handling (www.colfaxfluidhandling.com)
Electrical Submersible Pumps
ˆ Schlumberger (REDA) (www.slb.com)
ˆ Baker Hughes Centrilift (www.bakerhughes.com)
ˆ Canadian Advanced ESP (www.cai-esp.com)
ˆ Halliburton (www.halliburton.com)
ˆ Weatherford (www.weatherford.com)
33

46. 3.2.5 Field Application/Operators
The oil and gas industry being a dynamic one that has sought advancement in technology driven by
numerous factors such as extended water depth, harsher environments and optimization of lifecycle
performances. Over the years, subsea pumping technology has seen improvement from single phase
pumps to state of the art multiphase pumps, the table below shows various pump manufacturers and
offshore fields utilizing multiphase HAP and TSP technologies.
Table 11 – Field application of Multiphase pumps
34

47. 3.3 Sand Handling
The difficulty in accessing potent data from the formation depth and enclosing volumes has made
accurate prediction of sand production rate and volume an uphill task. Thus, over the last decade new
technologies for solids handling, especially sand, has been developed in order to increase separation
efficiency, reduce the equipment size and consequently improve hydrocarbon production.
3.3.1 Sand Separation Technologies
3.3.1.1 Screen / Filter (Gravel Pack)
For optimum hydrocarbon recovery, gravel pack, screen, and filters are widely accepted sand con-
trol techniques to restrict sand from leaving the wellbore into the processing modules either topside
or at the seabed. The completion equipment, especially the gravel pack, has a confirmed and tested
installation and working base and thus forms the bulk of conventional sand management. During
sand production controls in wells, these methods might yet allow the passage of 50 to 125 µm through
(even basic working conditions) interfering with operations. In event of failure in completion jobs
sand volume and particle sizes might increase swiftly, resulting in restricted recovery and damaged
equipment.
3.3.1.2 Cyclonic (Desander, Inline)
Desander
Desanders are cyclone (centrifugal devices with no moving parts) which remove solids from the well
stream. The produced crude oil is boosted into the wide top part of the cyclone at an angle roughly
tangential to its circumference. As the hydrocarbon streams around and steadily down the inner part
of the cone shape, solids are removed from the liquid by centrifugal forces. The solids continue round
and downward to exit at the hydrocyclone base and are discharged into an accumulator tank, from
which they are purged periodically.
Inline Desander
The Inline Desander removes sand from single and multiphase reservior fluid. The system can be
customized to suit any application. It use the same principle as the Desander and it is a compact
cyclonic unit without any reject streams that can handle a wide range of flow rates and achieve ef-
ficiencies up to 99%. Particle sizes down to 1 Micron can be removed depending on the size of the
unit. The sand removal efficiency can be seen on the Figure below.
35

48. Figure 26 – Graph showing relationship between sand removal efficiency and the diameter of inline
Desander
The fluid enters the Desander axially (or tangentially) while the pressure energy plus swirls element
initiates circular motion (Centrifugal force). The developed gravitational force separates sand particles
from the process stream and finally clean underflow reverses to outlet through the internal low-pressure
core.
Figure 27 – A typical inline Desander, image source FMC Technologies inline Desander, accessed
22/04/2015
The compactness of the inline separators allows it to be built and installed to standard piping speci-
fication, with limited weight and space requirement.
36

49. Figure 28 – Desander (FMC Technologies)
Wellhead Desander
The active influence for evolution of the wellhead Desander (WHD) was to upgrade the scope of
operation of the cyclonic technology to the multiphase flow regime. Multiphase Desander functions
based on the combined effect of the hydraulic and pneumatic cyclonic standards [Rawlins, 2002]. In
similar operating principle of a standard cyclonic devices, pressure energy is transformed to radial
and tangential acceleration to impart centrifugal forces on the enclosed fluids. The improved forces
speeds up the dissolution of phases with distintive densities. For a multiphase Desander, solids are
removed from the fluid stream. The transmitted force is about 400-5006 times higher than gravity,
resulting to fast-tracked removal of solids from fluids and also neutralizing the effect of any external
force on the performance of the cyclone. The equipment specification data of a multiphase desander
Halliburton is showed below on table 12.
37

50. Table 12 – Equipment specification data (Wellhead Desander Halliburton)
The removed solids are gathered into a vessel or accumulator chamber scheduled retrieval, with no
stoppage of the unceasing fluids flow as illustrated in Figure 28. Cyclonic technology has the highest
throughput-to-size ratio of any type of static separation equipment resulting in minimal installed
footprint and weight [Rawlins, 2003].
Figure 29 – A wellhead Desander with oversized accumulator integrated into the well bay of a pro-
duction spar.
3.3.1.3 Settling (Sand Jetting System)
The Sand Jetting system is about the most frequently employed upstream separator to get rid of
accumulated solids from the base of a gravity separators. Solid removal is achieved by introduction
of pressurized water with specially invented nozzles. The solids are subsequently disposed using sand
38

51. drains placed down the length of the vessel. The system can be configured to flush out the entire
vessel independently, or for sectional flushing of reduced length, in case of shortage in water supply.
Due to difficulty in cleaning a clogged nozzle, a sand is often set up, just above the sand drain,
to avoid the blockage of the nozzle before flushing. The sand pan is made up of a triangular cut outs
down its length through which the fluidized sand will pass to get to the sand drains. It is the basic
function of the flushing nozzles to keep these triangular openings clear of clogs, to guarantee effective
flushing rounds.
Figure 30 – Sand jetting for gravity settling systems
3.3.2 Sand Removal/Disposal
Separate solids from the well fluids and manage as separate flow stream. Different ways of handling
sand removal/disposal are available in the market the technologies / ways that could be fitted on our
subsea processing system are highlighted below.
ˆ Containerize: In order to collect the sand produced for a late removal, accumulation bags,
tubes and flexible containers can be implored. This can also be collected into a vessel and
retrieved by ROV, wireline or float to surface. As we are dealing with mature field and the
expected field life is 3/5 years, the simplest way to retrieve the sand for a late disposal is
containerizing it.
ˆ Inject into disposal well: All the sand produced is re-injected back into a disposal well and
route upwards to the topside facility and can be further handle.
ˆ Add back to oil stream:The separated sand is redirected to the oil and move up to the
platform processing facility. The main disadvantage is that a new process of sand separation
must be made topside in order to separate the sand again. In addition erosion on the valves
and pipes could occur.
ˆ Particle consolidation: Consolidate particles into solid or semi-solid shape, for ease of carry-
ing or contained seafloor disposal. The main techniques used are - Compress into puck which is
a mechanical densification; Adhesive polymer, an extruder can be added; Add cement to make
brick.
ˆ Clean and seafloor discharge: The sand removed from the well stream is treated, cleaned
and posteriorly discharged on the seafloor. The quality of the sand (Oil concentration) must
be within the established parameter by the local authority. Although OSPARCOM commis-
sion, which protects and conserve the north-east Atlantic and its resources, still allow the sand
dis¬charge (lwt% oil on dry solids) the ultimate aim is to cease the discharge, emission and
losses of hazardous substance by 2020. Despite the laws being restricted continuously, FCM
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52. technologies designed a outright solution for retrieving sand from the production stream and
for proper treatment of the sand for disposal as shown in the figure below 31:
Figure 31 – Sand handling treatment and disposal (FMC technologie: Sand Handling Brochure)
3.3.3 The consequences of sand deposits
Continuous deposition of sand in a separators results in corresponding proportional reduction of
available separator capacity. For instance, a separator half filled with sand only possess an effective
capacity of 50% with a corresponding half capacity lost to sand accumulations, thereby reducing the
retention time by 50%The operator would then need to decrease fluid flow to half in order to maintain
the residence time. The sand gathering can cause production drop. Another source of worry is that
a flushing system can be overwhelmed by excessive sand accumulation in the separator, and become
less capable of ejecting sand from the separator base. It would take a complete intervention process
to retrieve the separator to dispose the sand.
3.3.4 Suppliers
Several companies offer a wide range of sand handling facilities. Some of the more active are:
ˆ ASCOM
ˆ FMC
ˆ KERBS
ˆ IWS
ˆ DDS
ˆ HALLIBURTON
ˆ SCHULUMBERGER
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53. 3.4 Water Treatment Technologies for reinjection
The extraction of the hydrocarbon from a reservoir leads to the drop of the pressure in the reservoir,
which decreases the recovery. To deal with this issue, water is injected through injection wells into
the reservoir to maintain the pressure and the recovery.
Figure 32 – Predicted typical oilfield production profile with (secondary Production) or without
(Primary Production) water injection.
The volumes of water required for injection are reservoir specific but range from 110% to more than
400% of peak oil production rate.
This part reviews the technologies currently available in terms of seawater treatment, produced water
treatment and water reinjection.
3.4.1 Seawater Treatment Technologies
To maintain pressure into the reservoir, seawater is injected. However, the raw seawater requires to
be treated before injection to avoid well damages due to bacteria or corrosion.
Two kind of Seawater treatment are currently available:
ˆ Topside Seawater Treatment
ˆ Subsea Seawater Treatment
3.4.1.1 Topside Seawater Treatment
Topside seawater treatment deals with seawater treatment on the rig. This system is composed
of:
ˆ A Seawater lift Pump
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54. ˆ Filters
ˆ A Deaeration Tower
ˆ A Booster Pump
Note: The heat exchanger is not a seawater treatment device, but the seawater is used to feed it to
cool hydrocarbons, and then the water is treated.
Figure 33 – Topside Seawater Treatment System
Filters
ˆ Seawater Coarse Filter with Automatic Backwash
Figure 34 – Seawater Coarse Filter
The objective of this first filtration is to remove the coarse suspended solids that could deposit
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55. in equipment or plug pores of the reservoir formation [Humborstad, 2013].
This device is fully automatic, reliable and provides an efficient filtration. This technology
is used for more than 15 years in the North sea and worldwide.
This technology of coarse filtration offers a range of advantages:
– Automatic Cleaning
– No interruption required for cleaning operations
– Long life Time
– The design can be easily changed regarding seawater composition
Figure 35 – Coarse seawater filter package. (Courtesy of Cameron Process Systems)
The technical specifications of the filter are described in the following table:
Table 13 – Technical Specifications of a Coarse Filter
ˆ Fine Filtration
The seawater go through a second filter which allows a fine filtration. Indeed, solids up to
0.1 µm can be removed. During this step, scrimpy sand particles, algae, micoorganisms are
removed to obtain a seawater dree of solids.
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56. Figure 36 – TIMEX fine filters
Deaeration Tower
Removed dissolved oxygen widely presents into surface seawater is essential to avoid the corrosion of
the downstream devices or of the well and control the bacteria growth.
The gas removal process consist of [EQUIPMENT, 2012]:
ˆ Heat the seawater until its saturation temperature. The solubility of the oxygen will decrease
and attempted zero.
ˆ The heated seawater is agitated. Water is spraying in a thin film to reduce the distance required
by the gas bubble to be released by the water.
Figure 37 – Deaeration Tower
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57. Biocide Injection
Surface water contains biological constituents which may affect the good operating of the processing
system and of the water injection. Bacteria growth causes injection-well plugging and helps corrosion.
The most commonly biocide are used to kill anaerobic and aerobic bacteria, they are:
ˆ Chlorine (very effective for seawater)
ˆ Aldehydes
ˆ Amines
ˆ Chlorinated phenols
ˆ Organometallic compounds
ˆ Sulfur organic compounds
Suppliers
Topside Seawater Treatment packages are widely offered by Oil & Gas suppliers. The following
list quotes some of them:
ˆ Expro
ˆ Siemens
ˆ Veolia
3.4.1.2 Subsea Seawater Treatment
The seawater treatment can also take place subsea, on the seabed. It is called Sea Water Intake
and Treatment (SWIT). The treatment of the seawater is done by one single unit installed subsea
which performs three steps of water treatment (disinfection, solid removal and final cleaning) and
includes an injection pump [?].
Figure 38 – Solution with both the SWIT unit and an injection pump integrated into the same subsea
structure.
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58. First Technology Step: Disinfection
The first step of SWIT treatment process is the disinfection by Chlorine exposure. Chlorine is usually
used to remove microorganisms from water. The efficiency of the Chlorine treatment depend of the
chlorine concentration, the time of exposure and the pH of the water. When the water enter into
the SWIT, through grids on the top of the device, it goes through several electro chlorination cells
producing sodium hypochlorite: the disinfection process begins.
The disinfection process is controlled by sensors which allow the adjustment of the chlorine level
in the treated water and thus avoid the water to be polluted by a too high amount of chlorine.
Furthermore, the SWIT allows a exposure time of chlorine between 60 to 120 minutes against 60
to 90 for topside facilities. This long exposure time allows a very good kill rate of organic species
initially present in the seawater. This part of the process takes place into a chamber called “stillroom”.
Second Technology Step: Solid Removal
The second stage of SWIT seawater treatment is solid removal. Thanks to it particularly design,
the unit gives rise for low laminar and low speed flow to guarantee an effective settlement of solids.
The SWIT is able the remove 99% of particle greater than 18 micron with a flow capacity of 40,000
bpd.
Third Technology Step: Final cleaning
The last step of the seawater treatment happens in a hydroxyl radical generator which cleans the
water by breaking into smaller particles the dead bacteria. Finally the treated water is injected into
the reservoir thanks to an injection pump.
Suppliers
The SWIT technology is new and currently offers by a few suppliers. The two main companies
propose industry version of SWIT:
ˆ Seabox
ˆ Well Processing
3.4.1.3 Subsea Produced Water Treatment Technology
The produced water is the water separated from the hydrocarbons during the processing. This water
contains oil particles, organic and inorganic particles, bacteria, chemical. The concentration of these
particles depends of the field composition and the efficiency of the separation. To avoid pollution
of the environment (if the produced water is discharged) or of the reservoir (if the produced water
is reinjected), different kind of treatments have been developed. The most current produced water
treatments are:
ˆ Oxygen Removal / Deaeration
ˆ Bacteria Removal / Desinfection
ˆ Demineralization
ˆ Grease Removal/ Deoiling
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