final report-group 1
DESCRIPTION
Group project on economical optimization of an oil and gas fieldTRANSCRIPT
PCB 4033 FIELD DEVELOPMENT PLAN
GULFAKS FIELD, NORTH SEA
Prepared By: GROUP 1
Ngo Nguyet Tran ID: 15769
Negar Hadian Nasr ID: 17029
Shodiq Khoirur Rofieq ID: 17019
Emadeldin Ali Mahmoud Khairy Ali ID: 14695
Aidil Yunus Bin Ismail ID: 16760
Final Report submitted to the
Universiti Teknologi PETRONAS
in partial fulfillment of the requirement for the
Bachelor of Engineering (Hons)
Petroleum Engineering
MAY 2015
Universiti Teknologi PETRONAS
Bandar Seri Iskandar
32610 Tronoh
Perak Darul Ridzuan
CERTIFICATION OF APPROVAL
GULFAKS FIELD DEVELOPMENT PROJECT REPORT
Prepared by GROUP 1
Ngo Nguyet Tran ID: 15769
Negar Hadian Nasr ID: 17029
Shodiq Khoirur Rofieq ID: 17019
Emadeldin Ali Mahmoud Khairy Ali ID: 14695
Aidil Yunus Bin Ismail ID: 16760
Final Report submitted to the
Universiti Teknologi PETRONAS
in partial fulfillment of the requirement for the
Bachelor of Engineering (Hons)
Petroleum Engineering
Approved by,
------------------------------------------------ -----------------------------------------
(MR. BERIHUN MAMO NEGASH) (DR. SYAHRIR RIDHA)
FDP II SUPERVISOR 1 FDP II SUPERVISOR 2
UNIVERSITI TEKNOLOGI PETRONAS
ii
MAY 2015
CERTIFICATION OF ORIGINALITY
This is to certify that we are responsible for the work submitted in this project, that the
original work is our own except as specified in the references and acknowledgements, and
that the original work contained herein have not been undertaken or done by unspecified
sources or persons.
Ngo Nguyet Tran Negar Hadian Nasr
Shodiq Khoirur Rofieq Emadeldin Ali Mahmoud Khairy Ali
Aidil Yunus Bin Ismail
iii
ACKNOWLEDGEMENT
Firstly, we would like to express our sincere gratitude to all parties who has
contributed along the process of our Final Development Plan (FDP). We also
want to take this opportunity to thank to Geoscience and Petroleum
Engineering Department for giving us opportunity to experience and
complete this project as our learning process and get more information and
knowledge about FDP.
Our sincere thanks also go to thank Universiti Teknologi PETRONAS (UTP) for giving
students an opportunity to expose ourselves in the real working project. Apart from that, it is
important to us to handle the project by ourselves which definitely encourage student to be
more independent in the future.
We would like to extend our sincerest appreciation to Mr. Berihun Mamo
Negash and Dr.Syahrir Ridha for their constant support and help, on hand
working skills and exposure to oil and gas industry throughout our project despite their
hectic schedule. We are greatful to them for sharing their technical
knowledge which has indeed helped us to complete our FDP successfully.
Heartfelt thanks to the FDP coordinator, Ms Asyraf Md Akhir, for her
dedication in arranging the briefings and seminars to enlighten us about
this project. Apart from that, we feel very much obliged for herefforts in
finding appropriate supervisors to guide us throughout this project.
Last but not least, we would also like to thank all our fellow colleagues, friends and
family for their direct/indirect support and assistance throughout the project.
FDP provides us with a good opportunity to recap and apply what we have
learnt throughout the Final Year of Petroleum Engineering Program. It
provides us with a solid platform to overcome any obstacle in our future
technical endeavors.
Table of Contents
CERTIFICATION OF APPROVAL..........................................................................................................ii
CERTIFICATION OF ORIGINALITY....................................................................................................iii
ACKNOWLEDGEMENT.........................................................................................................................iv
CHAPTER 1 INTRODUCTION................................................................................................................1
1.1 Project Background..........................................................................................................................1
1.2 Problem Statement............................................................................................................................2
1.3 Objectives.........................................................................................................................................4
1.4 Scope of Study..................................................................................................................................4
CHAPTER 2 GEOLOGY AND GEOPHYSICS.......................................................................................6
2.1 Dimensional (2D) Cross Imaging.....................................................................................................6
2.2 Regional Setting...............................................................................................................................8
2.3 Hydrocarbon Petroleum System.......................................................................................................9
2.3.2 Reservoir Rock........................................................................................................................10
2.4 Depositional Environment and Facie Analysis..............................................................................12
2.4.1 Cretaceous...............................................................................................................................13
2.4.2 Tarbert.....................................................................................................................................13
2.4.3 Ness.........................................................................................................................................13
2.4.4 Etive.........................................................................................................................................14
2.5 Summary of Depositional Environment.........................................................................................14
CHAPTER 3 RESERVOIR ENGINEERING..........................................................................................15
3.1 Introduction....................................................................................................................................15
3.1.1 Objective..................................................................................................................................15
3.1.2 Data Given For Reservoir Study.............................................................................................16
3.2 Fluid Data Analysis........................................................................................................................16
3.2.1 Reservoir Pressure and Fluid Contact.....................................................................................16
3.2.2 Reservoir Fluid Studies...........................................................................................................19
3.2.3 Special Core Analysis (SCAL)................................................................................................25
3.2.4 Reserves Estimation................................................................................................................30
3.3 History matching............................................................................................................................33
3.3.1 Overview.................................................................................................................................33
3.3.2 History Matching Results from the study................................................................................35
3.4 Production Forecast & Optimization..............................................................................................44
3.4.1 Base case analysis....................................................................................................................44
3.4.2 Secondary recovery.................................................................................................................48
3.4.3 Water injection........................................................................................................................48
3.4.4 Water injection timing sensitivity analysis..............................................................................53
3.5 Enhanced Oil Recovery (EOR) Plan..............................................................................................55
3.5.1 Reservoir Properties of Gullfaks Field....................................................................................55
3.5.2 EOR Screening Criteria...........................................................................................................55
3.5.3 EOR Plan.................................................................................................................................57
3.6 Reservoir Management...................................................................................................................60
3.6.1 Reservoir Management............................................................................................................61
3.6.2 Reservoir Surveillance.............................................................................................................61
CHAPTER 4 DRILLING ENGINEERING.............................................................................................64
4.1 Introduction....................................................................................................................................64
4.1.1 Problem Statement...................................................................................................................64
4.1.2 Objective..................................................................................................................................65
4.2 Drilling Rig Selection.....................................................................................................................65
4.3 Rig Location...................................................................................................................................66
4.4 Well Trajectories............................................................................................................................67
4.5 Casing Design.................................................................................................................................69
4.6 Bit Selection...................................................................................................................................73
4.6.1 Size of Bit................................................................................................................................73
4.6.2 Type of Bit...............................................................................................................................73
4.6.3 Factors affecting Bit selection.................................................................................................74
4.7 Drilling Fluid System.....................................................................................................................77
4.8 Casing Cementation........................................................................................................................79
4.9 Potential Drilling Hazard................................................................................................................82
4.10 Well Control.................................................................................................................................84
4.10.1 Kick.......................................................................................................................................84
4.10.2 Kick identification.................................................................................................................85
4.11 Time and Cost Estimation............................................................................................................87
4.12 Drilling Optimization...................................................................................................................88
4.13 New Drilling Technology Consideration.....................................................................................89
4.13.1 New Drilling technologies.....................................................................................................89
4.13.2 Jet drilling..............................................................................................................................89
4.13.3 Utilization of laser technology in drilling..............................................................................92
4.13.4 Utilization of Electrical Plasma for Hard Rock Drilling.......................................................95
CHAPTER 5 PRODUCTION TECHNOLOGY......................................................................................99
5.1 Introduction....................................................................................................................................99
5.1.1 Overview.................................................................................................................................99
5.1.2 Objectives................................................................................................................................99
5.2 Completion String Design and Philosophy..................................................................................100
5.2.1 Completion Design................................................................................................................100
5.2.2 String completion..................................................................................................................101
5.2.3 Type of completion................................................................................................................102
5.2.4 Design Philosophy.................................................................................................................103
5.3 Wellhead and Christmas Tree Design..........................................................................................104
5.3.1 Wellhead................................................................................................................................105
5.3.2 Christmas Tree.......................................................................................................................106
5.4 Material Selection.........................................................................................................................109
5.5 Perforation Techniques.................................................................................................................111
5.5.1 Shaped Charged Characteristic and Performance.................................................................111
5.5.2 Spacing..................................................................................................................................113
5.5.3 Gun size.................................................................................................................................115
5.5.4 Conveyance Methods............................................................................................................115
5.5.5 Perforation Design.................................................................................................................117
5.6 Well Completion Plan..................................................................................................................118
5.6.1 Summary................................................................................................................................118
5.6.2 Well Completion Matrix........................................................................................................118
5.6.3 Proposed Completion Schematic...........................................................................................119
5.6.4 Completion String Design and Accessories..........................................................................122
5.7 Inflow/Outflow Performance Prediction......................................................................................124
5.7.1 Nodal Analysis......................................................................................................................124
5.7.2 Base Case Model...................................................................................................................125
5.7.3 Water Cut Limits...................................................................................................................128
5.7.4 Tubing Selection....................................................................................................................129
5.7.5 GOR Sensitivity.....................................................................................................................132
5.8 Artificial Lift Selection.................................................................................................................133
5.8.1 Selection Criteria...................................................................................................................133
5.8.2 Gas Lift Design......................................................................................................................135
5.9 Sand Control.................................................................................................................................139
5.9.1 Sand Failure Prediction.........................................................................................................139
5.9.2 Problems Caused by Sand Flow............................................................................................140
5.9.3 Sand Control Consideration and Design...............................................................................141
5.10 Potential Production Problems...................................................................................................147
5.10.1 Formation Damage..............................................................................................................147
5.10.2 Well Stimulation..................................................................................................................150
5.10.3 Flow Assurance Issues.........................................................................................................151
5.10.4 Other Production Problems.................................................................................................160
CHAPTER 6 FACILITIES ENGINEERING.........................................................................................161
6.1 Introduction..................................................................................................................................161
6.1.1 Overview...............................................................................................................................161
6.1.2 Problem Statement and Objectives........................................................................................161
6.2 Design Basis and Philosophy.......................................................................................................162
6.2.1 Design Basis..........................................................................................................................163
6.2.2 Reservoir Data.......................................................................................................................164
6.2.3 Rig selection..........................................................................................................................165
6.2.4 Platform selection..................................................................................................................166
6.3 Development Scenario..................................................................................................................169
6.3.1 Option A – 3 Steel jacket wellhead Platform + Pipeline.......................................................170
6.3.2 Option B – 2 Subsea development platforms + 1Steel jacket wellhead platform + Pipeline171
6.3.3 Option C –1 Subsea development platform + 2 Steel jacket wellhead platforms + Pipeline172
6.3.4 Option D – 3 Steel jacket wellhead Platform + FPSO..........................................................174
6.4 Engineering Design and Planning Considerations.......................................................................176
6.4.1 Platform Design.....................................................................................................................176
6.4.2 Gas Compression Requirements............................................................................................176
6.4.3 Water Injection Requirement.................................................................................................176
6.4.4 Telemetry System..................................................................................................................177
6.4.5 Corrosion Control - Production Facilities.............................................................................177
6.5 Platform Utilities and Service Facilities.......................................................................................178
6.5.1 Topside Structure...................................................................................................................178
6.5.2 Substructure...........................................................................................................................180
6.5.3 Wellhead module...................................................................................................................180
6.5.4 Separation..............................................................................................................................181
6.5.5 Metering.................................................................................................................................183
6.5.6 Well Control Panel................................................................................................................183
6.5.7 Flare system...........................................................................................................................184
6.6 Production Support Facilities.......................................................................................................185
6.6.1 Water injection......................................................................................................................185
6.6.2 Sea water Lifting and Filtering..............................................................................................185
6.6.3 Deoxygenation and Pumping.................................................................................................185
6.6.4 Gas compression facilities.....................................................................................................186
6.7 Gullfaks Pipeline System..............................................................................................................187
6.7.1 Pipeline sizing........................................................................................................................187
6.7.2 Pipeline Classification...........................................................................................................190
6.7.3 Pipeline modeling..................................................................................................................191
6.8 Operation and Maintenance Philosophy.......................................................................................192
6.8.1 Operation...............................................................................................................................192
6.8.2 Maintenance...........................................................................................................................193
6.9 Project Schedule...........................................................................................................................195
6.10 Abandonment..............................................................................................................................196
CHAPTER 7 ECONOMIC ENGINEERING.........................................................................................198
CHAPTER 8 HEALTH, SAFETY AND ENVIRONMENT.................................................................199
REFERENCES.......................................................................................................................................200
APPENDICES........................................................................................................................................202
Production Technology Appendices...................................................................................................202
List of Figures
Figure 1: Location of Gullfaks field in the North Sea................................................................................1Figure 2: Surface map of Base Cretaceous.................................................................................................6Figure 3: Cross section of producing exploration wells in Gulfaks Field..................................................7Figure 4: North South Cross section...........................................................................................................7Figure 5: East West Cross section..............................................................................................................8Figure 6: Regional view of Gulfaks...........................................................................................................9Figure 7: Depositional Environment and Lithology in Gullfaks..............................................................14Figure 8: Pressure Distribution for Well A10......................................................................................17Figure 9: Pressure Distribution for Well B9........................................................................................17Figure 10: Pressure Distribution for both wells..................................................................................18Figure 11: PVTi Software work Flowchart..........................................................................................20Figure 12: Constant Composition Expansion Diagram......................................................................22Figure 13: Differential Liberation Diagram........................................................................................22Figure 14: Oil-Water Relative Permeability Curves................................................................................26Figure 15: Gas-Oil Relative Permeability Curves....................................................................................26Figure 16: Water-Oil Capillary Pressure..................................................................................................27Figure 17: STOIIP and GIIP Calculation Concept...................................................................................29Figure 18: A10 Production Rate...............................................................................................................33Figure 19: A10 Bottom hole Pressure (base case)....................................................................................34Figure 20: A10 surrounding.....................................................................................................................35Figure 21: Cross Sectional View Of Reservoir........................................................................................36Figure 22: A10 Bottom Hole Pressure (case 1)........................................................................................36Figure 23: Gas Production Rate case 1.....................................................................................................37Figure 24: Match Attempt 1.....................................................................................................................38Figure 25: Match Attempt 2.....................................................................................................................39Figure 26: Match Attempt 3.....................................................................................................................40Figure 27: Water Production Rate............................................................................................................41Figure 28: Cumulative oil production for all the wells............................................................................42Figure 29: Cumulative oil production for all the wells except (C2, C3 and C4)......................................43Figure 30: Field oil production cumulative for all the 10 cases...............................................................44Figure 31: Oil production cumulative for all the 10 cases.......................................................................44Figure 32: Base case vs all the wells producing.......................................................................................45Figure 33: Natural depletion vs 5 injectors..............................................................................................47Figure 34: Natural depletion vs 3 injectors..............................................................................................47Figure 35: Natural depletion vs 4 injectors..............................................................................................48Figure 36: Natural depletion vs 2 injectors..........................................................................................48Figure 37: Natural depletion vs 1 injector................................................................................................49Figure 38: Comparison between different cases for water injection........................................................49Figure 39: Comparison between injector cases oil production.................................................................50Figure 40: Sensitivity analysis on water injection timing........................................................................51Figure 41: Natural depletion vs Optimum No. of injectors optimum injection timing case....................52
Figure 42: Nitrogen Injection Process for Recovery Improvement.........................................................55Figure 43: Carbon Dioxide Reinjection Process for Recovery Improvement*........................................56Figure 44: Types of Rig............................................................................................................................63Figure 45: Location of Rig.......................................................................................................................65Figure 46: Optimum places for the two platforms used for drilling of all the wells Yellow triangle for injection wells platform and red triangle for producer wells platform.....................................................66Figure 47: Well targets coordinates and wellheads coordinates...............................................................66Figure 48 Equivalent Mudweight vs Depth..............................................................................................68Figure 49: Insert Bit..................................................................................................................................71Figure 50: Milled Tooth Bit......................................................................................................................72Figure 51: PDC bit....................................................................................................................................72Figure 52: Drilling fluid circulation system.............................................................................................75Figure 53: Wellbore Profile.....................................................................................................................79Figure 54: Depth progress vs time for drilling plan of sample well A20.................................................85Figure 55 Jet drill tool..............................................................................................................................89Figure 56: Test well layout.......................................................................................................................89Figure 57: Rock failure due to spalling....................................................................................................91Figure 58 Conditions under which laser removes rock with or without significant melting...................92Figure 59 Plasma drilling system.............................................................................................................94Figure 60: Production Tubing String......................................................................................................100Figure 61: Wellhead and Christmas tree................................................................................................103Figure 62: Corrosion Resistant Alloy Selection Process*......................................................................108Figure 63: Shaped Charged Components...............................................................................................109Figure 64: The importance of using a conical liner in a shaped.............................................................110Figure 65: Picture demonstrates the angle of the cone and the liner material determines the penetration depth and the perforation's diameter.......................................................................................................111Figure 66: Perforation Charge Arrangement..........................................................................................112Figure 67: Results of underbalanced, balanced and overbalanced perforations.....................................114Figure 68: Single String Oil Producer Tubing........................................................................................118Figure 69: Single String Water Injector Tubing.....................................................................................119Figure 70: Base Case IPR for Gullfaks Field.........................................................................................124Figure 71: Base Case Nodal Analysis....................................................................................................125Figure 72: Sensitivity analysis on tubing size for reservoir pressure 2516psia......................................128Figure 73: Oil rate at different water cut without Gas Lifted.................................................................135Figure 74: Oil rate at different water cut with Gas Lifted......................................................................135Figure 75: Oil production influenced by various gas lift injection rate..................................................136Figure 76: Potential Sand Production...................................................................................................138Figure 77: Various types of mechanical sand control method...............................................................140Figure 78: Typical sand analysis distribution.........................................................................................142Figure 79: Typical relationships between mud type, cost & risk of formation damage.........................146Figure 80: Damage area during Perforation...........................................................................................147Figure 81: Possible well design for CO2 injection (from Cooper, 2009)...............................................150Figure 82: Production forecast profile for Gullfaks Field......................................................................161Figure 83: Types of offshore drilling rigs..............................................................................................163
Figure 84: Type of Oil Platform.............................................................................................................165Figure 85: Example of Steel Jacket platform.........................................................................................166Figure 86: Option A................................................................................................................................168Figure 87: Option B................................................................................................................................170Figure 88: Option C................................................................................................................................171Figure 89: Option D................................................................................................................................173Figure 90: Typical elevation view of an offshore platform....................................................................176Figure 91: Schematic of an offshore platform, illustrating the concept of modularization....................177Figure 92: Equipment arrangement plan of a typical offshore platform illustrating..............................177Figure 93: Process Flow Diagram.........................................................................................................178Figure 94: Horizontal Separator.............................................................................................................180Figure 95: Well Abandonment for Open Hole Completion*.................................................................195Figure 96: General Well Abandonment for Cased Hole........................................................................195
List of Tables
Table 1: Fluid Contacts Table...............................................................................................................18Table 2: The Experiment and PVT Parameters..................................................................................20Table 3: Compositional Analysis...........................................................................................................23Table 4: Facies classification of Core Sample..........................................................................................28Table 5: STOIIP Calculation....................................................................................................................30Table 6: GIIP Calculation.........................................................................................................................30Table 7: 10 cases with their following producing wells...........................................................................43Table 8: Water injection for different cases.............................................................................................46Table 9: Ranking the injector cases..........................................................................................................50Table 10: Parameters of the Gullfaks field...............................................................................................53Table 11: Summary of screening criteria for EOR Methods....................................................................54Table 12: Reservoir Surveillance and Its Purposes [9].............................................................................60Table 13: Rig Selection............................................................................................................................64Table 14: Types of Margin.......................................................................................................................68Table 15: Casing setting depth and Mud Program...................................................................................70Table 16: Bit Selection and Bit size.........................................................................................................74Table 17: Mud Program............................................................................................................................76Table 18: Classification of Well Cement.................................................................................................77Table 19: Cement Program.......................................................................................................................78Table 20: Summary Cement calculation..................................................................................................78Table 21: Drilling Schedule......................................................................................................................85Table 22: Comparison between different borehole completion approaches............................................98Table 23: Comparison of single and dual strings completion..................................................................99Table 24: Basic Types of Xmas Tree.....................................................................................................104Table 25: Xmas Configuration...............................................................................................................105Table 26: Summary of Dry Tree vs Wet Tree*......................................................................................105Table 27: Benefits vs Challenges of Dry Tree & Wet Tree*.................................................................106Table 28: Summary of the perforation system selected.........................................................................115Table 29: Well Completion Option for Gullfaks field...........................................................................116Table 30: Well Completion Matrix for Gullfaks Field...........................................................................116Table 31: Base Case Calculated data from Prosper................................................................................125Table 32: Effect of water cut on various reservoir pressures.................................................................126Table 33: Different tubing sizes with different reservoir pressure.........................................................129Table 34: GOR values with different reservoir pressure........................................................................130Table 35: Artificial lift methods and its features....................................................................................132Table 36: Comparison on production before and after installing Gas Lift.............................................134Table 37: Screen gauge used with various types of gravel size.............................................................143Table 38: Available Stimulation Techniques.........................................................................................148Table 39: General Material Specification and Characteristic.................................................................151Table 40: General Monitoring Methods for Corrosion..........................................................................152Table 41: Comparison of two common mitigation strategies for wax deposition..................................158
Table 42: Reservoir and Fluid Properties of Gullfaks Field...................................................................162Table 43: Option A.................................................................................................................................168Table 44: Option B.................................................................................................................................169Table 45: Option C.................................................................................................................................171Table 46: Option D.................................................................................................................................172Table 47: Proposed Project Schedule.....................................................................................................193
CHAPTER 1 INTRODUCTION
1.1 Project Background
Gullfaks is an oil and gas field in the Norwegian sector of the North Sea operated by Statoil. It was discovered in 1978, in block 34/10, at a water depth of 130-230 meters. The initial recoverable reserve is 2.1 billion barrels (330×106 m3), and the remaining recoverable reserve in 2004 is 234 million barrels (37.2×106 m3). This oil field reached peak production in 2001 at 180,000 barrels per day (29,000 m3/d). It has satellite fields Gullfaks South, Rimfaks, Skinfaks and Gullveig.
It was formed during Upper Jurassic to Lower Cretaceous with westerly structural dip gradually decreasing towards the east. The major north to south striking faults with easterly dipping fault planes divided the field into several rotated blocks. Central and eastern parts have been eroded by the early Cretaceous transgression. The field is related to block 34/10 which is approximately 175 km northwest of Bergen and covers an area of 55 km² and occupies the eastern half of the 10-25 km wide Gullfaks fault block (Fossen and Hesthammer, 2000). The Schlumberger geological modelling software product Petrel uses the Gullfaks field as the sample data set for its introductory course.
The project consists of three production platforms Gullfaks A (1986), Gullfaks B (1988), and Gullfaks C (1989). Gullfaks C sits 217 metres (712 ft) below the waterline. The height of the total structure measured from the sea floor is 380 metres (1,250 ft), making it taller than the Eiffel Tower. Gullfaks C produces 250,000 barrels per day (40,000 m3/d) of oil. The Tordis field, which is located 11 km south east of Gullfaks C, has a subsea separation manifold installed in 2007 which is tied-back to the existing Gullfaks infrastructure.
Figure 1: Location of Gullfaks field in the North Sea
1
Between November 2009 and May 2010 a well being drilled from Gullfaks C experienced
multiple well control incidents which were investigated by the Norwegian Petroleum Safety
Authority and summarized in a report released on 19 November 2010. The report stated that
only chance prevented the final and most serious incident on 19 May 2010 from becoming a
full-scale disaster.
Conditions have now changed from alluvial to the basin conditions which can be steady (e.g. a
lake) or can be dominated by waves and tidal motion in an oceanographic setting. In any case
the sediments can be redistributed and reworked by basinal processes such as coastal current
drift, long shore drift, storms, waves and tidal currents. The balance between the alluvial input
and the basin conditions determines the shape of the coastline and controls the delta evolution.
As the delta builds out in geological timescales is related to the sediment input and the
accommodation space, the stages are described relative to the amount of sediment increase or
decrease and the amount of sea level rise or fall.
Basically in this project the Gullfaks field is subdivided into 4 major stratigraphic units, which
are the Cretaceous, Tarbert, Ness and Etive formations. This petroleum system is a sequence
of sandstones, siltstones, shales and coals with maximum thickness of 300-400 m. The
Broom and Oseberg formations may represent early lateral infill of the basin whereas the
remaining formations comprise a major regressive (Ness and Etive formations) to transgressive
(Tarbert and Ness formations) clastic wedge (Helland-Hansen et al, 1992).
1.2 Problem Statement
As mentioned earlier Gulfaks field project has developed in three main stages or production
platforms: Gulfaks A, where is built in 1986, then followed by Gulfaks B, where is built in
1988 and finally Gulfaks C, where is built in 1989. The field was discovered and then starts the
production at 1978 and 1986, respectively.
Volumetric estimation is required at all stages of the field life cycle. In many instances,
a first estimate of how big an accumulation could be requested. At the very first stage or if the
2
data available is very sparse, a quick look estimation can be made using field-wide averages.
These approaches of estimation are applied here by using the Material Balance Techniques.
The field development project (FDP) report should cover all aspects of field
development which are as following:
Phase I: Geology & Geophysics and Petrophysics
Phase II: Reservoir Engineering
Phase III: Drilling Engineering, Production Technology and Facilities Engineering
Phase IV: Project Economics
Phase V: Sustainable Development and Health, Safety, & Environment
As of now, we are doing the Geology & Geophysics and Petrophysics part which is the
Phase I of the field development project.
Dataset for Gullfaks field are given which includes:
Well log data
Well deviation survey
Surface contour map
Well marker depth
Core data
PVT fluid data
MDT data
Well test data
Seismic data were not provided as part of the data acquisition. This will be one the cause of
uncertainties especially in geology development phase as seismic control is important in
interpreting important structural features.
3
1.3 Objectives
The objectives of the Gullfaks Field Design Project are to think deeply on how to develop and
improve the field performance. Through understanding the geological characteristic and
reservoir characteristic, the complexity distribution of oil and gas in the reservoir can be
overcame. Optimization the field performance, applying economics and environmental
elements are considered in the project. The objectives in formulating the best, possible FDP
will include the following:
a) Maximizing economic return
b) Maximizing recoverable hydrocarbons
c) Maximizing hydrocarbon production
d) Compliance with health, safety and environment requirements
e) Providing recommendations in reducing risks and uncertainties
f) Providing sustainable development options
The ultimate goal to come up with in this project is to maximize the return to operator within
the stipulated schedule. This goal must be achieved within technically and economically
viable development plan. The processes and development stages mentioned must be fulfill
with very focusing on the goal and follow the step of the development.
1.4 Scope of Study
The general scope of works for the Gullfaks FDP is:
1. To develop the 3D static model of Gullfaks Field using:
PETREL software
Manual method
2. Perform volumetric calculation for Gulfaks oil field:
STOIIP and GIIP, reserve estimation (proven, probable & possible)
4
Parameters: Gross rock volume, Net to Gross, porosity, Swc, oil and gas formation
volume factors, and fluid contacts.
3. To determine the Gross Rock Volume, Net to Gross (NTG), porosity and
saturation distribution profile, types of fluids and their contacts, Stock Tank Oil
Initially in Place (STOIIP) and Gas Initially in Place (GIIP).
4. To develop the 3D static model of Gullfaks Field using PETREL software.
5. To prepare a dynamic model from the 3D static model and perform
simulation to achieve the highest recovery factor (RF) and economic return of the
field.
6. To prepare well completion and production facilities design and propose a drilling
program.
7. To propose the most feasible and economical facilities in all the stages of
development.
8. To perform economic evaluation and sensitivity analysis for all development stages
and options.
9. To ensure the FDP is in compliance with national regulation and HSE
requirements.
5
CHAPTER 2 GEOLOGY AND GEOPHYSICS
2.1 Dimensional (2D) Cross Imaging
Surface map are maps given with contour lines drawn on it to indicate the depth of a particular area. Contour lines connect all the points on a plane that has equivalent depth. There are foursurfaces in Gulfaks field given in this project called, Base Cretaceous, Top Tarbert, Top Ness and Top Etive. Figure 2 shows one of the surface maps with contour lines that is being provided for this project:
Figure 2: Surface map of Base Cretaceous
6
Here, the 2D cross section shows the intersection of most producing exploration wells in
Gulfaks field. Based on this cross section, it can be seen that there is a fault represent by the
arrow and also anticline which generally referred to hydrocarbon reservoir trap.
Figure 4: North South Cross section
7
Figure 3: Cross section of producing exploration wells in Gulfaks Field.
Figure 5: East West Cross section
2.2 Regional Setting
Gullfaks field is located in the Norwegian sector of the northern North Sea along the western
flank of the Viking Graben. Gullfaks represents the shallowest structural element of the
Tampen spur. The field is related to block 34/10 which is approximately 175 km northwest of
Bergen and covers an area of 55 km2 and occupies the eastern half of the 10-25 km wide
Gullfaks fault block (Fossen and Hesthammer, 2000).
8
Figure 6: Regional view of Gulfaks
2.3 Hydrocarbon Petroleum System
Understanding petroleum system in Gullfaks field is imperative to determine how the
hydrocarbon is produced and migrated into the reservoir trap. For this section, petroleum
system description is based on literature review as seismic data are not given in this project.
2.3.1 Source Rock
9
The two main source rocks in this field are the oil-prone Draupne formation and gas-prone
Heather formation.
2.3.1.1 Draupne FormationThe Draupne formation is the main shale rock that forms the hydrocarbon source in this field.
Its physical characteristics include brownish black, medium to dark olive grey, non-
calcareous mudstones, which are locally silty and micaeous (Kubala et al, 2003). The
thickness of this formation is typically 50 – 250m, but may exceed 1200 m in localized area.
Immature organic materials in Draupne formation consist mostly of Type II kerogen
(William and Douglas, 1980) and are considered as highly prospective oil generating source
rock (Goff, 1983).
2.3.1.2 Heather FormationHeather formation is made up of dark grey silty mudstones with intermittent thin carbonate
layers. Thickness of this formation ranges up to 1000 m (Kubala et al, 2003) and it is typically
gas prone but studies by Gormly et al (1994). Total Organic Carbon (TOC) values are typically
between 2-2.5 % (Goff, 1983). The coal layers within the Ness formation of the Middle
Jurassic Brent Group are also categorized as main source rocks for gas generation in this
formation (Chung et al, 1995).
2.3.2 Reservoir Rock
2.3.2.1 Triassic and Lower Jurassic
The Triassic reservoir can usually be seen in tilted fault blocks with the variety properties of
Jurassic Cretaceous erosion and onlap. In North specifically at northern area will have most of
Triassic reservoir except of Snorre field. Snorre field have the accumulation of overlapping of
Lower and Middle Jurassic reservoir (Goldsmith et al, 2003). The reservoir units are
sandstones of early and middle Jurassic age, around 2000m subsea and measure several
hundred meters thick. Reservoir quality is generally very high, with permeability ranging from
few tens of mD to several Darcys depending on layer and location.
The properties of main reservoir intervals have thick fluvial channel and sheet flood deposits.
The characteristics of these reservoirs imitate deposition in terrestrial and semi-arid conditions
10
although the younger Statfjord formation has marginal marine influence increment. Reservoir
quality is both a function of the initial depositional facies with the more distal, matured and
cleaner sands having higher initial and ultimate porosities (Goldsmith et al, 2003). The
Statfjord formation is the most important hydrocarbon bearing reservoir in the category.
2.3.2.2 Middle Jurassic
Most of the Middle Jurassic reservoirs in the northern North Sea are arkoses and subarkoses
with quartz, clay minerals and feldspars constituting about 95% of the total mineralogy
(Humso et al, 2002). These sandstones are both quartz and calcite cemented at depths
exceeding 2500 m (Walderhaug and BjØrkum, 1992). The reservoirs form a thick clastic
wedge comprising laterally extensive interconnected fluvial, deltaic and coastal depositional
systems with porosities and permeabilities ranging from 20-30% and 50-500 mD respectively
at shallow depths (Giles et al, 1992).
In the northern North Sea, the Middle Jurassic reservoirs are represented by the Brent Group,
which comprises the Tarbert (youngest), Ness, Etive, Rannoch and Broom formations (Vollset
and Dore, 1984). The basal Brent is typically upper shoreface sandstones whiles the upper part
of the group is represented by transgressive sandstones (Gautier, 2005).
2.3.2.3 Upper Jurassic
Up to 100m of Upper Jurassic shales (Heather Formation) are locally preserved in the
hanging walls to the main faults in the Gullfkas Field, particularly in the western part.
2.3.3 Traps and Seals
There are present of traps and seals in the North Sea especially at Gulfaks field itself. That’s
where many accumulated places have stored the hydrocarbon. This trapping are likely happen
because of tectonic movement of the formation plate and hence fault is formed which have
sealed by fine grains (Gautier, 2005). As example, Viking graben have hydrocarbon trapped in
11
lateral trapping and sealed. The reservoir rocks are juxtaposed by non-reservoir rocks at faults
contacts (Gautier, 2005).
2.4 Depositional Environment and Facie Analysis
The location where particular sediments are deposited is known as depositional environment.
The depositional environment is essential to understand various physical, chemical and
biological processes associated with the deposition of particular type of sediments and
also their lithification through cementing and compaction.
The Gullfaks field occupies the eastern half of a major, 10-25 km-wide, north-northeast-
trending fault and is bounded by faults with kilometer-scale offsets. The sand reservoir
formation of the Gullfaks Field forms a subordinate, but extremely heterogeneous, reservoir in
the Gullfaks field.
The reservoir is divided into three main units, but only the upper unit contains
significant producible hydrocarbons. This reservoir was deposited in a tide-dominated deltaic
setting and it is characterized by a significant proportion of heterolithic facies (mm/cm-
scale sand-shale laminations). The individual sand laminae within reservoir heterolithic
facies are fine- to medium-grained with a porosity range of 25-40 % and a horizontal
permeability range of 10-2000 mD. However, total effective permeability within this
unit is strongly influenced by the sand-shale ratios of the heterolithic facies and by the
lateral extent of individual day laminae.
It is known that Middle Jurassic deposits of the reservoirs in Gullfaks field are shown
by the deltaic sediments with deposition strongly affected by regressive/transgressive
cycles and happened during the late phase of post-rift subsidence following the Late
Permian/Early Triassic rifting (Ryseth, 2000). The thickness of this formation is from ongoing
faulting due to tectonic movement of the plate and thermally driven subsidence.
The most of oil in the Gullfaks field is found by the Brent group formation. The Brent group
consists of four main stratigraphic formations there are Cretaceous, Etive, Ness and Tarbert.
The depositional environment of each stratigraphic formation is different so it is caused
12
to difference in reservoir characteristic. For overall, the Brent group formation consists of
sandstone, shale and siltstone and depositional environment is a delta system and has a very
good reservoir. The oil recovery factor in this formation is 60 % (Statoil Hydro, 2007).
2.4.1 Cretaceous
Newest pattern of plate rifting and erosion of uplifted fault parts in the late Jurassic and early
Cretaceous was followed by a major rise in sea level across the Gullfaks formation. This result
in Cretaceous sediments deposited in uncertainty on late Jurassic sediment of the North Sea
and later called as Base Cretaceous Unconformity (BCU).
In North Sea, specifically at northern part the Lower Cretaceous deposits comprise shallow
marine mudstone, calcareous shale and mixed ratio of sand. In Late Cretaceous, the sea level
maintained to be at peak and the clastic sedimentation is decreased where this then dominated
by planktonic carbonate algae. However, in area of Viking graben, the carbonates are not pure
and have been replaced by marls. The Upper Cretaceous contain mudstones and minor
imbedded of limestone of the Shetland Group (Surlyk et al, 2003).
2.4.2 Tarbert
Tarbert formation is located at the upper of Brent group and it is the youngest
formation. The thickness of this formation is around 75 to 105 m and the range of
permeability is 300 to 10000 md. Sediment structures and typical features in this formation
comprises of medium fine grained cross stratified sandstone, coarcenning upwards sequences
in lower part containing shale and coal beds and bioturbated. The depositional environment
this part is progradational sequence in an overall retreating/transgressive part of the
delta. Furthermore, reservoir characteristic of this formation is very good reservoir
quality, very good lateral continuity and poor sand strength (Tollefsen et al., 1992). The total
oil reserve and oil recovery factor in Tarbert is 135 MSm^3.
13
2.4.3 Ness
Ness formation is located at the upper of Brent group same as Tarbert formation. The thickness
of this formation is around 85 to 115 m and the range of permeability is 200 to 6000
md. Sediment structures and typical features in this formation consists of sandstone
units comprise minor mouth bars, thin sand bodies and bioturbated. The depositional
environment this part is delta top and fluvial marginal marine. Moreover, reservoir
characteristic of this formation is very poor reservoir quality, poor continuity of sand
and moderated poor sand strength (Tollefsen et al., 1992). It is a heterogeneous formation with
a lot of fault present and it is leading to complex communication pattern internally and with
other formation, so it makes a poor reservoir quality. The total oil reserve and oil recovery
factor in Ness is 46 MSm^3.
2.4.4 EtiveEtive is located at the lower of Brent group. The thickness of Etive formation is around 15
to 40 m and the range of permeability is 2000 to 7000 md. Sediment structures and
typical features in this formation consist of medium coarse grained massive cross- stratified
sandstones. The depositional environment this part is foreshore and beach. In additional,
reservoir characteristic of this formation is very good reservoir quality, very good lateral
continuity and poor sand strength (Tollefsen et al., 1992).
2.5 Summary of Depositional Environment
Depositional environment of Gullfaks field can be summarized as shown subsequently
14
CHAPTER 3 RESERVOIR ENGINEERING
3.1 Introduction
The purpose of Reservoir engineering is to make a comprehensive study of the recovery
mechanism of the reservoir and its production forecast. Reservoir engineering phase includes
the analysis of PVT data, separator test, well test results and others. Moreover, the history
matching of reservoir properties associated with the given build-up and drawdown test of well
A10 was performed. The data histories including bottom hole pressure, gas rate, water rate and
oil rate were recorded for A10 well for duration of 16 days, from 1-July-2013 until 16-July-
2013.
This chapter will also discuss the recovery mechanism of the reservoir and reservoir
management system. The number of wells and well placement location could be
determined from the analysis of the available data.
3.1.1 Objective
The main objectives of Reservoir engineering part is the investigation and analysis of the
following items to:
Analyze reservoir data and properties based on PVT and well test data.
To history match bottom hole pressure, gas rate, water rate and oil rate of well A10
from observed data and Petrel model.
Estimate cumulative production based on drive mechanisms used.
Forecast production profile.
Propose a development plan for the reservoir based on the number of wells, type of
completion and well placement.
Suggest a reservoir management plan for enhancing the recovery and optimize
reservoir performance.
15
3.1.2 Data Given For Reservoir Study
Well RFT and Historical Production Report – Singlerate
Well RFT and Historical Production Report – Multirate
3.2 Fluid Data Analysis
3.2.1 Reservoir Pressure and Fluid Contact
In this study, Reservoir Data start with recognizing the contacts within the wells. This sets of
data called water-oil contact (WOC) and gas-oil contact (GOC) is essential for reservoir
management and reservoir optimization plan in future. GOC is defined as the transitional
contact which separates the gas phase and oil phase in the particular reservoir and thus forming
a zone containing mixtures of gas and oil. Since the gas is lighter in term of density as
compared to oil, this give a result where the gas to be accumulated above the contact while the
oil is located below the contact. In the other hand, WOC is defined as the contact that separate
between oil and water in a reservoir. Water phase is found below the contact as it is denser than
the water phase.
Well A10 and Well B9 are the wildcat wells in the Gulfaks reservoir and these wells were
drilled in order to test the potential of hydrocarbon in the reservoir. From the graphs below, the
GOC and WOC is determined from the sudden change of the characteristic of the pressure
gradient.
Specifically in the project, the fluid contacts are only determined through the Formation-tester
pressure surveys due to the limitation of the availability data. Since the MDT Formation
Pressure Data Report for Well A10 and Well B9 are given, GOC and WOC for this reservoir
will be identified by plotting the data. In general, pressure gradient of gas is likely around
0.10psi/ft, oil is from 0.25 to 0.35psi/ft whereas for water is from 0.40 to 0.55psi/ft.
16
Figure 8: Pressure Distribution for Well A10
Figure 9: Pressure Distribution for Well B9
17
Figure 10: Pressure Distribution for both wells
Data from both wells were combined into one plot (above) to identify the major fluid gradients.
It can be seen that there are 2 shifts in the pressure gradient, hence 3 straight lines. 3 lines of
best fit were plotted and their formulas were found. Obtaining of the contacts would require
solving the simultaneous equations. The two plots above show the plots of data from each well
separately. Consequently, the lines of best fit differ when data from each well is considered
alone. The results are shown below:
Table 1: Fluid Contacts Table
RESULTSGOC WOC
TVD (m) P (bar) TVD (m) P (bar)Well A10 Only 1701.370 167.927Well B9 Only 1891.000 178.706Both Wells 1700.670 167.925 1891.810 178.773AVERAGE 1701.020 167.926 1891.405 178.740
18
3.2.2 Reservoir Fluid Studies
PVT analysis of reservoir fluid samples provides an important input for reservoir numerical
modeling. A set of Gulfaks field oil and gas separator samples were collected. The fluid
properties need to be known over a wide range of temperatures and pressures.
However, we are also unable to measure directly all the things we need to know about the
hydrocarbons. Hence, the fluid is modelled mathematically by matching equations of state
(EOS) to the fluid properties obtained from lab experiments and field measurements. The
matched equation of state can then be used to generate the fluid’s PVT data at various ranges
of pressure and temperature and this data can then be used as input for computational
simulation of fluid flow in the reservoir.
During the part of building the base fluid model, Equation of State should
be chosen. Experimental analysis gives the most accurate result in predicting the
characteristic of the fluid, but the major setback is this method requires a long time to conduct
the experiment and sample should be required from the reservoir. The condition of the sample
also will affect the accuracy of the experiments. The second method which is using the
Equation of State is more towards analytical method which saves time and does not require
sample of the reservoir fluid to conduct the experiments. The accuracy of this analytical
method depends greatly on the Equation of State used. Equation of State is merely an
equation relating pressure, temperature, volume and composition. Equation of State provides
reliable volumetric data over the used equation.
In PVT analysis, there are various experiments could be conducted to get the PVT parameter.
Using PVTi, we could also simulate these experiments to produce the same PVT analysis. The
experiments and PVT parameters and PVTi Sofware Workflow Chart are illustrated in the
table and figure below.
19
Table 2: The Experiment and PVT Parameters
Bubble Point Test Constant Composition
Expansion Test (CCE)
Differential Liberation
Test
(DLL)
Saturation Pressure
Liquid density
Relative Volume Liquid Viscosity
Vapor Viscosity
Gas Oil Ratio
Gas Formation Volume
Factor.
20
Input the composition of Hydrocarbon into the pvti software and build the base fluid model.
Input the expremintal given data.
Apply different equation of state (EOS) which give best matching with given expremintal data.
Perform regression upon the fluid model.
Select the fluid model with least errors between the observed and calculated data.
Tabulate the results of other PVT parameter which not given.
Figure 11: PVTi Software work Flowchart
The available data from the fluid study report (DST#1) contains details of three experiments; a
Constant Composition Expansion (CCE) experiment, a Differential Liberation (DL)
experiment and a Bubble Point experiment. Used for all three experiments is a PVT cell, which
is a vessel whose internal volume is known under a wide range of temperatures and pressures,
and can be maintained in a constant (adjustable) temperature environment. The cell is
equipped with a high-pressure window through which you can see (and measure) any liquids
present. Pressure and volume changes are effected by introducing or withdrawing mercury
under pressure directly at the base of the cell, or above a floating piston that forms the “roof”
of the cell. Ports exists for the charging and withdrawal of fluids during the experiments.
Initially the cell is charged with a mixture that we believe represents the reservoir composition.
The cell is then left to attain equilibrium at the desired temperature and pressure, some cells
having the ability to agitate the contents to help achieve this more rapidly.
21
3.2.2.1 Constant Composition Expansion (CCE) experiment
Starting at a pressure above reservoir pressure, the cell pressure is gradually reduced, and the
expanding volume measured. While the mixture remains above the dew point, the Z-factors
can be calculated directly, as the number of moles in the cell will be known from the charging
measurements. Several pressure traverses will be made in order to define the dew point as
accurately as possible. As the pressure is reduced below the dew point, the condensed liquid
volume is measured and reported as a function of the cell volume at the dew point. This
measurement is all that can be obtained from the experiment once the dew point is crossed, as
the number of moles in the liquid, and its composition are unknown. However, it is an
important set of experimental data for fluid modelling. The ultimate result obtained from this
experiment is the oil’s bubble point pressure, which is at 2516.7 psia.
Figure 12: Constant Composition Expansion Diagram
3.2.2.2 Differential Liberation (DL) experiment
The Differential Liberation experiment is usually only performed on nonvolatile oils. Most
crude oils analysed by this experiment generally report the so-called black oil properties of
gasoil ratio, Rs, oil formation volume factor, Bo and gas formation volume factor Bg which is
22
sufficient for inclusion in most simulators with black oil PVT treatments, such as ECLIPSE
100. Black oil properties of crudes (and volatile fluids using an extended black oil treatment,
including a vaporising oil term Rv, the condensate-gas ratio) can be generated from a
compositional description via an Equation of State and the simulation of suitable experiments.
Figure 13: Differential Liberation Diagram
The data obtained from this experiment include:
Oil Formation volume factor: 1.1 bbl/stb
Solution Gas Oil Ratio: 1.1342 scf/stb
Oil Density : 45.11 lb/ft3
3.2.2.3 Compositional Analysis
Detail hydrocarbon compositions from C1 to C7+ were obtained. The compositions of
separator oil, separator gas and calculated wellstream are tabulated as follows.
Table 3: Compositional Analysis
Component
Mole%, Yi MW yi*MW Tcri, R yi*Tcri, R
Pcri, psia
yi*Pcri, psia
23
CO2 1.49 0.0149 44.0100 0.656 547.91 8.164 1071 15.958N2 0.27 0.0027 28.0100 0.076 227.49 0.614 493.1 1.331C1 60.66 0.6066 16.0430 9.732 343.33 208.264 666.4 404.238C2 15.32 0.1532 30.0700 4.607 549.92 84.248 706.5 108.236C3 10.14 0.1014 44.0970 4.471 666.06 67.538 616 62.462IC4 1.88 0.0188 58.1230 1.093 734.46 13.808 527.9 9.925NC4 4.82 0.0482 58.1230 2.802 765.62 36.903 550.6 26.539IC5 1.43 0.0143 72.1500 1.032 829.1 11.856 490.4 7.013NC5 1.30 0.0130 72.1500 0.938 845.8 10.995 488.6 6.352C6 2.59 0.0259 86.1770 2.232 1113.6 28.842 436.9 11.316C7+ 0.09 0.0009 218.0000 0.196 1350 1.215 255 0.230SUM 100 1 27.83 472.45 653.6
3.2.2.4 PVT Result (Summary)
The following is the summary of the results obtained from the PVT analysis:
Reported Reservoir Conditions
Reservoir Pressure: 2516 psia
Reservoir Temperature: 220 °F
Constant Composition Expansion
Bubble-point Pressure: 2516.7 psia
Differential Liberation Test
Oil Formation Volume Factor: 1.1 bbl/STB
Solution Gas-Oil Ratio: 1.1342 Mscf/STB
Oil Density: 45.11 lb/ft3
24
Reservoir Fluid Viscosity
Oil Viscosity: 1.33 cp
25
3.2.3 Special Core Analysis (SCAL)
In the Special Core Analysis (SCAL) report, there are a total of three (3) core samples from a
single well in Gulfaks field which were taken at depth intervals of 1794-1796m, 1824-1827m
and 1903-1905m respectively. The reservoir condition is reported at reservoir pressure of 2516
psia and reservoir temperature of 220 deg F. Moreover, no Routine Core Analysis (RCAL)
report available for this project. Core samples which were used for lab measurements to obtain
different rock properties (relative permeability, capillary pressure) are discussed in the
following sections.
3.2.3.1 Capillary pressure and J-function
The capillary pressures data obtained from SCAL analysis studies is plotted into Capillary
Pressure curve and were used to derive J-function to develop initial water saturation
distribution in the reservoir according to the sand facies. Capillary pressure is the difference in
pressure across the interface between two immiscible fluids, it’s a function a saturation and
saturation history (drainage or imbibition) for a given reservoir rock and fluids at a constant
temperature. The role of capillary pressure curves in the initial oil distribution lies in estimation
of the saturation of fluids in transition zones. Depending on the facies type, the pore size
distribution is different, which implies a difference of residual water saturation and residual gas
saturation. A poor reservoir rock will demonstrate higher connate water saturation and longer
transition zone as compared to a good reservoir rock.
From the graph below, the capillary pressure curve from the three (3) samples can actually be
grouped according to the sand quality. It is illustrated that sample 1-2001 has the highest
quality of rock type among others. Each sand facies will be assigned with its own capillary
pressure to further include the heterogeneity of the reservoir.
26
Table 4: Facies classification of Core Sample
Core sample Permeability (mD) Porosity Facies classes
1-2001 385 0.28 Good sand
1-3001 58 0.175 Shaly sand
1-4003 212 0.22 Fair sand
J-function is used to transform the capillary pressure curve to a universal curve before
classifying according to the sand facies. The capillary pressures were used to derive J-function
to develop initial water saturation distribution in the reservoir. Rock samples with different
pore-size distribution, permeability, and porosity will yield different capillary pressure curves.
Poor reservoir rock will show higher connate water saturation and higher transition zone due to
smaller capillary tube.
Table 5: Laboratory-reservoir fluid properties for capillary conversion
27
These pressures however, must first be converted from laboratory measurement to reservoir
condition before they are utilized. Hence, we will use the formula as follows.
Equation used to convert to reservoir fluid system:
(Pc)res=(σcosθ)res
(σcosθ )lab
(Pc)lab
Capillary pressure for different reservoir system can be express as follow:
28
Where:
θres /θlab : Reservoir/lab contact angle σres /σlab : Reservoir/lab interfacial tension
Where:
Pcoil-water : Capillary pressure for oil-water system Pcgas-water : Capillary pressure for gas-water system
The capillary pressures calculated previously will then be converted to dimensionless function
of water saturation for rock type classification using the J-function method.
Usually a constant of 0.26145 is multiplied with the J-function values for field data units
conversion. The water saturation is usually normalized to eliminate the different critical end
points saturations. To normalize the water saturation, we will use the formula:
Where:
Sw : Water saturation corresponding to the capillary pressure value
Swi : Initial water saturation of core sample
J-function values versus normalized water saturation were plotted to classify the capillary
curve according to sand facies. The average J-function curve is then de-normalized to obtain
the gas-oil/water-oil capillary pressure curve according to the rock classifications. Capillary
pressure curve will describe the saturation profile in the dynamic modeling.
29
Where:
Pc (Sw) : Capillary pressure at different wetting saturation σ cos θ : Interfacial tension and cosine θ of oil/gas-water k : Rock permeability (Darcy) Ø : Rock porosity (fraction)
Figure 15: Capillary pressure curve classification based on J-function vs. Sw
From the plot above, the capillary pressure curves from the three (3) samples can actually be
grouped according to the sand quality. Each average curve will then be de-normalized by
selecting the nearest matched curve and de-normalization will be based on the values of the
core sample selected. In this project, based on the facies modeling of the reservoir, 3 average
curve selected as good sand, fair sand and shale sand. Each sand facies will be assigned with
its own capillary pressure to further include the heterogeneity of the reservoir.
30
Good sand Shale sand Fair sand
3.2.3.2 Relative Permeability
Relative Permeability for each core sample of Gullfaks field are generated and displayed in the
consequent figures. There are two relative permeability curve generated for each facies namely
gas oil relative permeability curve and water relative permeability curve.
The nonwetting phase relative permeability curve shows that the nonwetting phase begins to
flow at the relatively low saturation of the nonwetting phase. The saturation of the oil at this
point is called critical oil saturation Soc.
The wetting phase relative permeability curve shows that the wetting phase will cease to flow
at a relatively large saturation. This is because the wetting phase preferentially occupies the
smaller pore spaces, where capillary forces are the greatest. The saturation of the water at this
point is referred to as the irreducible water saturation Swir or connate-water saturation Swi—
both terms are used interchangeably.
31
Figure 16: Oil-Water Relative Permeability Curves
.
3.2.4 Reserves EstimationThe estimation of the HCIIP is based on the availability of any pressure and production data.
Volumetric calculation is basically one of the common practices by all the geologists and
geophysicists in industry to evaluate the economic value of that certain particular field
development. As the time goes by, some of the information of the reservoir will de dynamic as
a function of time, therefore this volumetric calculation must be viewed as the present
estimation as it is expected to change throughout the reservoir life. HCIIP can be separated into
oil and gas phases.
Stock Tank Oil Initially In Place (STOIIP)
Gas Initially In Place (GIIP)
32
Figure 17: Gas-Oil Relative Permeability Curves
HCIIP is a function of the Gross Rock Volume (GRV) multiplied by the Net to Gross (NTG),
Porosity and oil or gas saturation. All these fractions are used to discount any volume of the
GRV that does not add to the hydrocarbon volume. Furthermore, HCIIP is not the volume of
hydrocarbons in the reservoir, but at stock tank (at the surface) conditions. Hence the name
STOIIP: Stock Tank Oil Initially In Place when talking about oil. For gas the name is just
GIIP.
To calculate stock tank conditions the temperature, composition and pressure of the fluids in
the reservoir is used to calculate a Formation Volume Factor. This factor is used to express the
expansion of the gas when brought to surface. For oil, it is used to express the volume decrease
due to gas escaping from the fluid when the pressure drops. In addition to that, HCIIP is not the
volume that is eventually produced as no reservoir can be produced to the last drop of oil and
gas. The recovery factor is a last factor that can be used to estimate the recoverable volume of
Hydrocarbons but is very much dependent on the development method for the field.
Figure 18: STOIIP and GIIP Calculation Concept
33
𝐻𝐶𝐼𝐼𝑃 = 𝐺𝑅𝑉 ×𝑁/𝐺× Ø × 𝑆h𝑐 × 1/𝐹𝑉𝐹For oil volumetric calculation:
𝑆𝑇𝑂𝐼𝐼𝑃 = 𝐺𝑅𝑉 ×𝑁/𝐺× Ø × (1 - 𝑆𝑤) × 1/𝐵𝑜For gas volumetric calculation:
𝐺𝐼𝐼𝑃 = 𝐺𝑅𝑉 ×𝑁/𝐺× Ø × (1 - 𝑆𝑤) × 1/𝐵𝑔
3.2.4.1Stock Tank Oil Initialy in Place (STOIIP)
Table 6: STOIIP Calculation
STOIIP CALCULATION
GRV(m^2)*10^6 Net to gross porosity 1-Sw Bo STOIIP (m^3)*10^6BC-TT TT-TN TN-TE
1266.239581 0.0820.3360.421
sum in m^
0.255 0.734 1.1 17.66742646917.4225358 0.255 0.734 1.1 52.4508145869.2069361 0.255 0.734 1.1 62.26569418
3 unit 132.3839351
3.2.4.2Gas Initialy in Place (GIIP)
Table 7: GIIP Calculation
GIIP CALCULATION
GRV(m^2)*10^6 Net to gross porosity 1-Sw Bg GIIP (m^3)*10^6BC-TT TT-TN TN-TE
18.59410431 0.0820.3360.421
sum in m^
0.255 0.734 0.005696 50.1020360414.28571429 0.255 0.734 0.005696 157.727528113.60544218 0.255 0.734 0.005696 188.2179403
3 unit 396.0475044
34
From calculation above, we conclude that Stock Tank Oil Initially In Place (STOIIP) to be
132.3839351 (m^3)*10^6 and Gas Initially In Place (GIIP) at 396.0475044 (m^3)*10^6.
3.2.5Well test analysisWell testing is a very effective way to test the properties of the drilled well and some of the reservoir average properties. The basic idea of well testing is to always monitor and record the change in reservoir pressure with the change in flow rate. Then plotting the relationship between them on a Cartesian, semi-log or log-log scale and from these plots, some of the reservoir properties can be determined such as:
Formation permeability
Reservoir‟s boundary conditions
Average reservoir pressure
Skin effects
In this project the Drill Stem Test DST for well A10 is analyzed mainly to determine the average reservoir permeability which can assist in the history matching as well as in determining the drainage radius for each well for better well placement Well A10 is an exploration well. For simplicity single rate test was used. There was two test one drawdown test the other is build up test.
Pansys software was used in analyzing the well test data. And the following findings were made.
The test overview was as following
Figure 19 well test over view
35
A pressure draw down test at a constant rate of 4715 bbl/day, for 73 hours, followed by a
shutin build up test to complete 190 hours.
3.2.5.1 Drawdown down test analysis
It was analyzed on a semi log plot and the results are in the following figure.
Figure 20 semi-log plot of the drawdown test
The test shows straight line trend of MTR early and then boundary effect takes over. And
shows k=28.6 md , And radius of investigation of 764 ft.
By matching it’s log-log plot to boundary condition type curve on pansys. The following was
optained.
36
Figure 21 Boundary type curve matching
The match showed that there is a nearby single fault of L=67.5 ft. and this fault is the reason
why MTR region is so small.
3.2.5.2 Buildup test analysisFrom log-log plot the MTR region was identified by the flat deferential pressure trend.
Figure 22 log-log plot of pressure and differential pressure for buildup
And the MTR region could be identified by the dashed lines. Then by using this region from
the semi log plot, K and radius of investigation could be calculated.
37
Figure 23 Semi-log plot of build-up test
K was found to be 191 md and radius of investigation was found to be 2619 ft.
And the type curve plot confirms the presence of a single fault as shown in the figure below.
Figure 24 boundary type curve plot for build-up.
And the fault is of l=90ft.
It is to be noted that, Build up test results are more reliable than draw down tests. As flow rate
is easily maintained at zero rather than fluctuating around 4715bbl/day drawdown. Also, it
lasted for longer time and has shown flat differential pressure which is a sign of MTR.
38
Thus it can be assumed that, average permeability around well A10 is 191 md and that radius
of investigation of the test reached 2619 ft.
3.3 History matching
3.3.1 Overview
In general, the reservoir simulation process can be divided into three main phases:
I. Input data gathering
II. History matching
III. Performance prediction
The first step in a simulation study is the collection and analysis of data. Data must be acquired
and evaluated with a focus on its quality and the identification of relevant drive mechanisms
that should be included in the model. Input data normally contains of general data, grid data,
rock and fluid data, production/injection data and well data.
The next phase of the reservoir simulation study is the history matching phase. The goal of
history matching is to prepare a flow model that can contribute to reservoir management
decision making. History matching is an iterative process that makes it possible to integrate
reservoir geoscience and engineering data. Starting with an initial reservoir description, the
model is used to match and predict reservoir performance by adjusting the reservoir parameters
of a model until the simulated performance matches the observed or historical behavior.
The history matching procedure consists of the following sequential steps:
39
1. Pressure matching
2. Saturation matching
3. Productivity matching
The pressure is usually the first dynamic variable to be matched during the history matching
process. A comparison of estimated reservoir pressures obtained from well tests of a single
well on successive days shows that errors in reported historical pressures can be up to 10
percent of pressure drawdown. While production rates are usually from monthly production
records. The modeler specifies one rate or well pressure, and then verifies that the rate is
entered properly by comparing observed cumulative production with model cumulative
production. After the rate of one phase is specified, the rates of all other phases must be
matched by model performance.
The fundamental concept in history matching is the hierarchy of uncertainty, where relative
permeability data are typically placed at the top of the hierarchy of uncertainty because they
are modified more often than other data. Initial fluid volumes may be modified by changing a
variety of input parameters, including relative permeability endpoints and fluid contacts.
Typically, observed and calculated parameters are compared by making plots of pressure
versus time, cumulative production (or injection) versus time, production (or injection) rates
versus time, and GOR, WOR, or water cut versus time. However, there are limitations on
history matching process including unreliable or limited field data, interpretation errors, and
numerical effects.
Once a match of historical data is available, the next step involves predicting the future
performance of a reservoir when the modeler switches from rate control during the history
match to pressure control during the prediction stage of a study. This prediction could be for
existing operating conditions or for some alternate development plan, such as infill drilling or
waterflooding after primary production, and so forth. The main objective is to determine the
optimum operating condition in order to maximize the economic recovery of hydrocarbons
from the reservoir.
40
3.3.2 History Matching Results from the study
The only available field data for history matching comes from Well A10’s multi-rate well test,
which is run on constant liquid rate. Hence, the only logical way to history match is to run the
well A10 in the petrel model on constant rate and try to match the observed data, which
consists of the bottom hole pressure profile as well as the water and gas production curves. A
history strategy was set up accordingly in order to produce the required schedule section for
our field’s data set to run with Eclipse simulators. As shown in the figure below, the history
strategy was created from observed data and hence it overlaps/follows the observed data points
exactly.
Figure 25: A10 Production Rate
41
Matching A10 bottom-hole pressure
As expected, the base case BHP (shown as red curve HM0 in graph below) does not match the
observed data. This means that certain properties of the model (rock and fluid properties) need
to be changed in order to bring the BHP curve down. Although our group did not do a
comprehensive sensitivity analysis of all possible parameters that can be changed, we did a
quick sensitivity study and found conclusively that absolute rock permeability was the most
sensitive parameter. Hence we should not need to change it much in order to get a good match.
Also, it is quite evident that the reservoir must have a higher permeability than the real
reservoir and that is why it can produce at the same rate with higher BHP pressures. Hence our
group tried changing the permeability of the cells surrounding the well in the I, J and K
direction to find the best combination that can match our observed data.
Figure 26: A10 Bottom hole Pressure (base case)
42
Figure 27: A10 surrounding
Our group has decided to not multiply the permeability array of the whole reservoir because we
feel that it does not make sense to change the properties of cells that do not contribute to well
A10’s production. Furthermore, those properties have been derived from accurate well log and
core data, and we strongly feel that it should not be changed unless we have better quality data
with better certainty. Hence, to solve this, we created a geometrical property with radius of
600m around the well A10 (shown in figure on the right) and used it to apply a filter when
modifying the reservoir properties. In this way, only the properties of the cells within a 600m
radius of the well gets changed. 600m radius was chosen as an appropriate radius after we did
some investigation into the maximum possible drainage area of the well when critical
properties such as permeability are lowered. Part of this investigation included taking cross
sectional views of the reservoir and seeing how far away from the well the production is taking
place (as shown in figure below).
43
Figure 28: Cross Sectional View Of Reservoir
After much investigation and trying out numerous combinations of altered permeabilities, our
group found out that the best match we can get is when we multiply permeability in I direction
by 0.7 and permeability in J direction by 0.9. The resulting match is shown in the figure below.
We call this case 1.
Figure 29: A10 Bottom Hole Pressure (case 1)
44
Matching A10 gas production rate
Figure 30: Gas Production Rate case 1
As can be seen in the figure above, the gas production rate of case 1 is so high that the
observed data look like they are zero when the two data are compared. Hence, our team set out
to change several things in order to try to lower gas production and to get a match:
1. Raising the gas cap
Our group thought that maybe gas coning was happening and that enormous amounts of
gas were being produced from the gas cap. In order to test this theory, we raised the gas-oil
contact so that it was way above the topmost grid-block. In other words, there no longer a
gas cap. However, as the figure below shows, this only reduced gas production slightly,
which shows that production from the gas cap was not significant at all. This meant that it
was either we have a wrong fluid model (with too high Rs) or that the pressure drop was
causing gas to evolve out of the oil too quickly in the oil zone and that it is getting
produced in favour of the oil.
45
Figure 31: Match Attempt 1
2. Stopping movement of free gas
In order to test our theory and stop the preferable production of free gas, we tried changing
the relative permeability curve of the gas in order to restrict the movement of the free gas
phase. However, even after lowering the gas relative permeability curve by half, there was
only a slight drop in gas production (shown by brown curve in figure below). So we tried
setting the relative permeability curves to zero instead. The drop in gas production was also
not enough (shown as red curve in figure below).
46
Figure 32: Match Attempt 2
3. Changing the fluid model
Finally, to check if it was our fluid model that was wrong, we used pre-sets to build a “dead
oil” fluid model, which is known to have a low solution gas ratio. However, the figure
below shows that even though the gas production from the “dead oil” case was
significantly lower than that of case 1, we can clearly see that it was still too high compared
to the observed data, which still looks “squashed” down to zero when compare to the two
simulated gas production. In conclusion, our group believes that something must be wrong
with the observed data and not our model. Therefore we cannot and should not match our
data to the observed gas production rate.
47
Figure 33: Match Attempt 3
Matching A10 water production rate:
Matching this rate curve was not a problem because there was no aquifer below the oil zone in
the region where well A10 was producing. Hence, as can be seen by the graph below, the
water production for the case 1 showed zero production just like the observed data.
48
Figure 34: Water Production Rate
Case 1 was deemed the best matched case and was used as the model going forward into the
production prediction and optimization stage.
49
3.4 Production Forecast & Optimization
In order to identify the best possible strategy to develop and produce the field, sensitivity
analysis was done. The simulation model was run with different configurations in steps in
order to quantify the development uncertainties and depletion strategies. Due to the time
constraints and the inability to identify the dominant drive mechanism of the field, the
sensitivity analysis was done in a way that would give the best possible results. They are
discussed in the following sections.
3.4.1 Base case analysis
For the base case, first, all the existing 12 wells (using the existing
completions – perforation Intervals) were run as producer individually with
natural depletion drive via fluid expansion for 10 years and they ranked
based on their individual performance and their ranking is used as a guide
for the next step. Based on the production of each well, the wells with the
lowest production rate removed from the combination and next case will
run without those wells. The process is continued till the last well and the
total cumulative production is compared among the cases to identify which
combination of wells is the best. The results are summarized below:
50
Figure 35: Cumulative oil production for all the wells
Based on the figure shown, the production of following wells (C2, C3 and
C4) is very low. It’s because these wells are located below oil water
contact. Even though the best location for perforation was chosen for all of
them still they result in having early water breakthrough.
51
Figure 36: Cumulative oil production for all the wells except (C2, C3 and C4)
As it’s clear from this figure, well B9 has the highest production rate
followed by A20, A10, A19, A16, A15 and C5. There are 10 different cases
run in order to find the optimum number of producing wells.
Based on the results taken from these graphs, the case number 7 with 7
wells B9, A20, A10, A19, A16, A15 and C5 has the highest cumulative oil
production. This case will be selected as the optimum case with the best
52
CASE 1 2 3 4 5 6 7 8 9 10NO OF WELLS 1 2 3 4 5 6 7 8 9 11
B9 B9 B9 B9 B9 B9 B9 B9 B9 B9A20 A20 A20 A20 A20 A20 A20 A20 A20
A10 A10 A10 A10 A10 A10 A10 A10A19 A19 A19 A19 A19 A19 A19
A16 A16 A16 A16 A16 A16A15 A15 A15 A15 A15
C5 C5 C5 C5B8 B8 B8
C6 C3C2C4C6
TOTAL OIL PRODUCTION (sm3) 715700 1221900 1647100 1973000 2301400 2501500 2670800 2761800 2755300 2523000
-1 1 3 5 7 9 1170000
570000
1070000
1570000
2070000
2570000
CUMULATIVE OIL PRODUCTION CASES
No. of producers
CU
MU
LA
TIV
E O
IL P
RO
DU
CT
ION
(sm
3)
Figure 37: Field oil production cumulative for all the 10 casesFigure 38: Oil production cumulative for all the 10 cases
producing wells. It is called our base case and the following tests will be
done on this case.
Figure below show comparison between the base case with the case with
all the 12 wells open for production:
53
Figure 39: Base case vs all the wells producing
3.4.2 Secondary recovery
To improve the oil recovery for this field, secondary drive mechanisms such
as water flooding is suitable as the reservoir is supported by an aquifer
from the bottom therefore individual water flood cases are analyzed which
each will be explained in the following sections. However for this section,
the injection wells are selected from the existing wells not by adding a new
well. Selection of injectors was done based on the location of each wells
which are supported by aquifer.
3.4.3 Water injection
To improve the oil recovery of the Gullfaks field, water injection scheme is proposed. The
injection wells used are the existing proposed wells given in FDP data pack (C4, C6, B8, C3
and C2). The injection wells are controlled by the bottom hole pressure of the wells which is
set to 400 bar in the PETREL 2013 simulator. A base case with water injections was created.
There are as well 5 different cases define for water injection process.th first case is 1 injector
with 7 producing wells (base case). The second, third, fourth and fifth are 2, 3 4 and
5 injectors.
54
CASES 1 2 3 4 5NO OF INJECTORS 5 4 3 2 1
C4 C4 C4 C4 C4C6 C6 C6 C6B8 B8 B8C3 C3C2
Table 9: Water injection for different cases
The best base case with natural depletion is compared with the base case with 1,2,3,4 and 5
water injectors. The results are as follows:
55
Figure 40: Natural depletion vs 5 injectorsFigure 41: Natural depletion vs 3 injectors
Figure 42: Natural depletion vs 4 injectors
Figure 43: Natural depletion vs 2 injectors
From the results simulated, it can be seen that production with water injection strategy is better
than the one with natural depletion strategy. Hence it is determined that the field will be
produced with water injection strategy rather than just natural depletion alone. For the water
injector base case, the combination of 7 production wells with water injection will be used.
Based on this figure the 4 injectors, case no 2 (C4, C6, B8 and C3) give
higher oil production result compare to the rest. However based on the
optimum case curve the 3 injector and 4 injectors doesn’t have much
difference so 3 injector will be selected as the best case for water injection.
56
CASES 1 2 3 4 5NO OF INJECTORS 5 4 3 2 1
C4 C4 C4 C4 C4C6 C6 C6 C6B8 B8 B8C3 C3C2
TOTAL OIL PRODUCTION (sm3) 5283700 5434000 5329300 4718700 3536800
Figure 44: Natural depletion vs 1 injector
Figure 45: Comparison between different cases for water injection
Table 10: Ranking the injector cases
The
next step is to do sensitivity analysis on the water injector combination with 7 producer wells.
3.4.4Water injection timing sensitivity analysis
After choosing the optimum number of injection wells, Sensitivity analysis was made to find
the optimum timing for water injection.
The timing for water injection is very important in reservoir production as injecting water into
the reservoir at different time will lead to different production profile.
The sensitivity analysis was made on 5 different cases (Injection after 2 years, 4 years, 6years
and 8years) and compared to the optimum injection case with injection right from start.
57
1 2 3 4 53536800
4036800
4536800
5036800
5536800
INJECTOR CASES
No. of injectors
TO
TA
L O
IL P
RO
DU
CT
ION
(sm
3)
Figure 46: Comparison between injector cases oil production
Figure 47: Sensitivity analysis on water injection timing
The results showed that the field’s production is at its optimum when the
water injection started since the beginning of the production. This also
indicates that the reservoir’s aquifer has little effect on the production and
water injection is needed in order to fully maximize the field’s hydrocarbon
recovery.
Figure 48: Natural depletion vs Optimum No. of injectors optimum injection timing case.
58
3.5 Enhanced Oil Recovery (EOR) Plan
3.5.1 Reservoir Properties of Gullfaks Field
The reservoir and fluid properties of the Gullfaks field are summarized in following table.
Table 11: Parameters of the Gullfaks field
Reservoir Property Value Oil Gravity , API 64.2 Reservoir Temperature 220 F Original Reservoir pressure 2516 psia Oil Viscosity ,cp 1.337cp Porosity 0.27 Horizontal permeability 270md Reservoir Depth , ft >5000Residual Oil Saturation 77.4
3.5.2 EOR Screening Criteria
Screening criteria have been widely used to identify EOR applicability in a particular field
before any detailed evaluation is started. EOR screening represents a key step to reducing the
number of options for further detailed evaluations. Table Summary of screening criteria for
EOR Methods shows the summary of screening criteria which is based on a combination of the
reservoir and oil characteristics of successful projects plus the optimum conditions needed for
good oil displacement by the different fluids. The suggested criteria in following table are
informative and intended to show approximate ranges of good projects but they may be
misleading
59
Table 12: Summary of screening criteria for EOR Methods
60
3.5.3 EOR Plan
Screening processes were carried out to identify potential EOR processes for Gullfaks
reservoirs. Based on swelling test provided, it indicates that Immiscible Gas Flooding and CO2
gas Injection which are suitable and meet the criteria in order to be implemented at Gullfaks
field.
3.5.3.1 Immiscible Gas Flooding
In this method, nitrogen is injected to the reservoir to maintain the pressure and to produce
better sweep efficiency. This is achieved by creating miscibility or partial miscibility which
reduces the viscosity of oil and cause oil swelling, which resulting in increasing in the recovery
factor.
Figure 49: Nitrogen Injection Process for Recovery Improvement
61
3.5.3.2 CO2 Gas Injection
The main objective of carbon dioxide injection gas is to swell the oil, lower its viscosity
which result in lowering the interfacial tension between the oil and rock, thus improving the
microscopic sweep efficiency. CO2 flooding can obtain high oil recovery from light oil and
especially in water flooded reservoir in some cases. Miscible CO2 injection can extract the light
to intermediate components of the oil, and develop miscibility to displace the crude oil from
the reservoir. The Figure below illustrates the carbon dioxide injection process.
Figure 50: Carbon Dioxide Reinjection Process for Recovery Improvement*
*Retrieved from http://energy.gov/fe/science-innovation/oil-gas-research/enhanced-oil-recovery
CO2 volumes injected during a process are typically at least 25% PV. A volume of relatively
pure CO2 is injected to mobilize and displace residual oil. Through multiple contacts between
the CO2 and oil phases, intermediate and higher molecular weight hydrocarbons are extracted
62
into the CO2-rich phase. Under proper conditions, this CO2-rich phase will reach a
composition that is miscible with the original reservoir oil. From that point, miscible or near-
miscible conditions exist at the displacing front interface. Under ideal conditions, this
miscibility condition will be reached very quickly in the reservoir and the distance required to
establish multiple-contact miscibility initially is negligible compared with the distance between
the wells. Gas injection often comes with early breakthrough and viscous finger issue due
to its low viscosity.
For future EOR considerations, the main factors that should be considered are the current oil in
place, residual oil Saturation (Sor), and the economical, geo-political and management policy.
Further testing should be done to estimate the current oil in place or residual oil in place and
evaluate how much oil would the EOR recover. Current oil price would also play a role in
deciding whether the EOR plans would be feasible at the time of evaluation. Government
incentives such as tax and royalty would also be a deciding factor.
63
3.6 Reservoir Management
Reservoir engineering phase deals with the human, technological and financial aspects of the
field, while trying to minimize the expenses and investment done to the development of the
field and also maximizing the recovery factor of the hydrocarbons in the reservoir [8].
It is envisaged the optimum development plan for Gullfaks field is by 7 production wells (B9,
A20, A10, A19, A16, A15 and C5). Oil produced will be on 1st January 2013 for
production life of 10 years. The reservoirs will be depleted naturally supported by a water
injection strategy. To improve the oil recovery of the Gullfaks field, water injection scheme is
proposed. Consequently, there are three additional injection wells, which are C4, C6, and B8. It
is realized that the field’s production is at its optimum when the water injection started since
the beginning of the production. This also indicates that the reservoir’s aquifer has little effect
on the production and water injection is needed in order to fully maximize the field’s
hydrocarbon recovery. Thus, Water injection at Gullfaks will commence at the first year of
production. Target production has to be monitored closely. Full field review should be done
and any plans for infill drilling can be considered later on. Future plans for the field might be
revised when more information regarding the field is obtained.
The reservoir management plan of Gullfaks field consists of the reservoir goal, operational
strategies to reach the objectives, and reservoir surveillance plan to identify performance issues
and to enhance the operations of the reservoir. To be able to manage reservoirs properly and to
optimize recovery, it is important that proper reservoir management and monitoring is carried
out, particularly during the early dynamic phase of production.
64
3.6.1 Reservoir Management
The goals of reservoir management are:
To maximize oil recovery by optimizing reservoir performance throughout reservoir
lifetime.
To run the well test on new and existing wells for data acquisition on reservoir
properties and characteristics.
To implement secondary recovery for pressure maintenance by injecting water and
maintaining reservoir pressure above bubble point.
To practice reservoir simulation in order to provide enhancement of reservoir models
for reliable predictions.
To monitor reservoir daily, monthly and annual production for reservoir performance
and maintaining operation strategies.
To implement tertiary recovery in order to improve sweep efficiency of trapped
residual oil.
To install surface facilities than can fulfill the requirement for reservoir management
and development.
3.6.2 Reservoir Surveillance
In operating and monitoring reservoir performance, several surveillance methods need to be
used in order to minimize the uncertainties in reservoir characteristics. With the lack of data
acquired on new drilled wells in early field development, this surveillance done on reservoir
can give better quality on data and reservoir information further to comprehend about the
architecture of the reservoir [12]. Suggested surveillance is done on the operations stated in table
below.
65
Table 13: Reservoir Surveillance and Its Purposes [9].
Parameters Purposes
Bottom hole pressure measurementsTo monitor reservoir pressure; maintaining pressure above bubble point with the respective drawdown pressure.
Pressure transient studiesFlowing Build Up (FBU) and drawdown test can be carried out in order to determine reservoir properties such as permeability, oil rate, productivity index and skin for new drilled and existing wells. To investigate the effect of early and late time region such wellbore storage, skin, faults and reservoir boundary.
Production loggingProvide data on water and oil saturation and fluid contacts.
Flow rate measurements.Monitoring oil production and water injection rate Record and limiting water production after 50% of water cut
Sand Production MonitoringMonitoring sand production through production test choke inspection and fluid samples by recording amount of sand produced.
Every effort will be made to ensure Gullfaks field reservoirs will be managed prudently and in
accordance to Norway government guidelines. Reservoir management for Gullfaks field can be
divided into two phases, which are initial production and routine production phases. In every
phase, appropriate data acquisition is planned to achieve specific objectives in order to
optimize the field development planning as well as to effectively monitor reservoir
performance to maximize recovery.
Periodical surveillance is essential to obtain optimal reservoir management. Bottomhole
pressure measurements and monthly well tests are especially important to determination of the
reservoir parameters and aquifer strength. The aquifer strength could be confirmed only after
66
several years of production. Revisions to the STOIIP and GIIP should be done after drilling the
development wells in the drilling campaign.
Initial flowing and build-up (FBU) will also be carried out at the first opportunity available.
From initial FBU, the initial reservoir pressure, the permeability, the skin factors, the reservoir
boundary and other useful reservoir parameters would be obtained. The initial FBU data will
be analyzed to ensure the reservoir characteristics are considered in revising the reservoir
management and production allocation.
Routine production rate test will be performed once a month to determine its oil, gas, and water
rates. The measurement of surface condition such as wellhead pressure (THP), choke size and
casing head pressure and the API gravity of the produced liquid hydrocarbon will also be
recorded during the monthly production test.
Static bottom hole pressure (BHP) surveys will be performed annually. This would be useful,
as it would permit material balance study. Key wells will need to be identified so as the six
month BHP surveys are done on these wells. While the remaining active wells will be the
rotational wells and BHP surveys will be done on annually basis. The BHP survey data would
be used to continually monitor the reservoir pressure and areal pressure distribution,
particularly in the late field life.
The production test rate and BHP survey must comply with the procedures approved by
Norway government. The results of the reservoir simulation models will be used as a guide for
the reservoir surveillance engineers to determine the optimal production strategy. Sensitivity
analyses of different depletion plans have been carried out to increase the recovery factor such
as number of wells, types of wells, water injection.
Due to unconsolidated nature of the reservoir rocks, sand production will be monitored from
the monthly test choke inspection and fluid samples by recording amount of sand produced.
Close monitoring, especially on water breakthrough, would provide indication of any
problematic wells or reservoirs for early diagnosis. Early corrective measures could be
undertaken to prevent well/reservoir problems and prevent excessive water production in early
field life.
67
CHAPTER 4 DRILLING ENGINEERING
4.1 Introduction
Drilling operations have a substantial importance in the Field Development Plan as it
represents a large portion of the total project’s costs. This phase of FDP describes the stages
that should be done in order to design development plan using the information that are
achieved from geosciences and reservoir engineers. The Gullfaks field is located in the
Tampen area, a part of the Viking Graben in the North Sea. Due to the large
area of the field, which is 50 km2, Gullfaks was developed with three
platforms, Gullfaks A, B and C. Geologically, Gullfaks was described as the
most complex field that had been developed so far on the Norwegian
Continental Shelf (NCS) when it was put on production.
The development plan of Gullfaks Field is to drill 7 production wells (B9,
A20, A10, A19, A16, A15 and C5), with 3 injection wells (C4, C6, and B8).
The proposal of the development should contain the objectives of the well
and the location of the target with the geological cross section. All
activities involve in the drilling phase are to be conducted according
to the standard guidelines provided by PETRONAS HSE. On the other hand,
the drilling program should comprise of these important elements such as
drilling rig to be used for the well, proposed location for the drilling rig, hole
sizes and depths together with the casing sizes and depths. Other aspects
like drilling fluid specification, well, control equipment and bits and
hydraulics program are also included.
4.1.1 Problem Statement
There are several steps that should be done during drilling operations that
include: selection of platform and suitable offshore rig, well
trajectories, casing design, bit selection, drilling fluid system, casing
cementation and drilling hazards. Also the overall cost estimate for the
68
drilling operation should be calculated. Finally, drilling optimization and
new drilling technology should be investigated. For this part of the Field
Development Plan, first suitable platform and offshore rig should be
selected based on some criteria. Casing plan should be done to make the
drilling operations cost-efficient and safe.
4.1.2 Objective
The main objectives of drilling operations in the Field Development Plan of Gullfaks field are
as follows:
Propose an appropriate platform and offshore rig applicable in our field.
Design well trajectories, casing design, selection of bits, drilling fluid system, casing
cementation and also drilling hazards.
Estimate overall time and cost of the drilling operations.
4.2 Drilling Rig Selection
Drilling technology is continually expanding, and some rigs combine elements from different
models to attain particular capabilities. Generally the main types of offshore oil rig include the
following:
Tender-Assisted-Drilling (TAD).
Jack-up Rig.
Semi-submersible.
Drillship.
69
Figure 51: Types of Rig
Rigs classification is based on the of location, whether offshore or onshore and the rig’s
capacity as in the effective drilling depth that can be attained. Offshore rigs perform the
same function as the land drilling rig. The difference between these two is that land rig has
complexity in terms of mobility while the offshore rig is in the aspect of the design.
There are two main types of offshore drilling rigs, which are floating type and bottom-
supported unit. Floating unit type would include the semi-submersible (bottle-type, column
stabilized), barge rig and drill ship. Meanwhile, bottom-supported unit comprised of posted
barges, bottle-type submersibles, arctic submersibles), jackups and platforms. In shallow water
or swamps, a barge which is a shallow-draft, flat-bottomed vessel water or swamps is used. In
general, table below shows the most common used offshore oil rigs.
Table 14: Rig Selection
Drilling Rig Type Water depth (ft) Average Daily Rate (USD)
Jack-up Rig 200-500 $60,000-100,000
Semi-submersible Rig 1499-4000 $298,000-432,000
Drillship 4000-5000 $243,000-524,000
Sources: Rig zone website, Riglogix http://www.rigzone.com/search.asp?q=jack+up+rig
The sea depth for Guillfaks is around 130-230m (427-755ft). Initially, Jack-up rig and semi-
submersible rig are preferable due to variation of water depth.. Since proposed location have
water depth ranging from 130-150m (400-500ft) therefore Jack up rig is choosed.
4.3 Rig Location
One of the most important parts in the well trajectory planning is the rig
location. To propose the best location of the rig, many factors should be
taken into consideration such as the total length of the measured depths
70
(MD) from the rig to the targets (wells) and the drilling trajectory process
(type of trajectory, build up rate and drop down rate). These factors affect
economically on the drilling cost and process. The less drilled measured
depths, the less the drilling cost. For these reasons the proposed rig
location has been decided to be at 3 different point.
451000 452000 453000 454000 455000 456000 457000 458000 4590006778000
6779000
6780000
6781000
6782000
6783000
6784000
6785000
6786000
6787000
6788000
c platform
b platform
a platform
c6
c4
b8
a15
c5
b9
a10
a16
a19
a20
Drilling Rig Locationa20
a19
a16
a10
b9
c5
a15
b8
c4
c6
a platform
b platform
c platform
y (m)
x (m
)
Figure 52: Location of Rig
4.4 Well Trajectories
In this project, PETREL software will be used to help in designing the wells. Completion and
reservoir drainage considerations are key factors in well path design. All producer wells and
injector wells will be drilled from two platforms (one for the seven producer wells and another
for the three injector wells) to keep the wells from only two platforms wells will need to be
deviated to reach the target zones.
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The original plan was, calculating the optimum place for injector and producer drilling rig
using average X and y coordinates of the targets of the wells producer and injector wells
respectively. To keep minimum distance drilled possible for all the wells.
Figure 53: Optimum places for the two platforms used for drilling of all the wells Yellow triangle for injection wells platform and red triangle for producer wells platform
The reason for choice of the deviated wells from common platforms (one for drilling and one
for production), is due to saving cost of production and injection facilities being installed each
in a single place. Also, the installation of production or injection facilities on a single platform
without the other will allow for more space to be used on the platforms. As well, to facilitate
transportation of the produced oil from the single production platform as compared to several
producing platforms.
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producer wells x y x ya20 456397.9 6782861a19 456416.7 6782831a16 456510.4 6784012a10 456979.1 6782712b9 456727.7 6785559c5 453503.7 6783002a15 456645.1 6781580
injector wells x y x yb8 457746.9 6787093c4 454640.2 6786211c6 451503.8 6781788
Well head coordinatesTarget coordinates
456168.64 6783222.6
454630.32 6785030.5
Target coordinates Well head coordinates
Figure 54: Well targets coordinates and wellheads coordinates
However, this was changed since we have found data in literature suggesting that in Gulfaks field. There is three platforms. Namely A,B and C.
So the well trajectories followed the following patterns.
Drilling rig coordinatesWell target X y x ya20 456397.92 6782861.07
456589.8255 6782799.335
a19 456416.68 6782831.44a16 456510.4055 6784012.02a10 456979.0637 6782712.412a15 456645.0581 6781579.733 b9 456727.6572 6785559.446
457237.2964 6786326.03b8 457746.9356 6787092.614 c5 453503.7221 6783001.797
453215.9155 6783666.89c4 454640.1872 6786210.631c6 451503.8373 6781788.243
Table: Well targets vs optimum drilling location
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451000 452000 453000 454000 455000 456000 457000 458000 4590006778000
6779000
6780000
6781000
6782000
6783000
6784000
6785000
6786000
6787000
6788000
c platform
b platform
a platform
c6
c4
b8
a15
c5
b9
a10
a16
a19
a20
Drilling Rig Location
y (m)
x (m
)
Figure 55 Drilling rigs location
4.5 Casing Design
The casing design have many details that must be taken into consideration such as determination of
casing setting depth, size, grade and weight of the casing for each interval. The casing shoe setting
depth is usually a function of the drilled formations. Pore pressure and fracture pressure gradient can
affect directly to the casing setting depth. The casing size is determined depending on the well depth. In
deep wells, the drilling process needs to start drill with large hole size and many casings to cover the
hole length, but it starts with smaller hole size and less number of casings in shallow wells. The casing
weight and grade are selected based on the load conditions (burst, collapse and tensile) for the well. In
general, the main functions of casing are:
• To isolate unstable formations.
• To protect weak formations from the high mudweights that effect on zone fracture.
• To isolate zones with abnormal high pore pressure.
• To seal off lost circulation zones.
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• To allow selective access for production from or into the reservoir.
• To provide structural support for the wellhead and BOPs.
All the casing configuration is designed based on pressure containment, cost effectiveness and
completion requirements. The design is based on SPE casing design criteria and it must conform to
PETRONAS Procedures for Drilling Operation (PDO), PETRONAS Technical Standards (PTS), PCSB
Drilling Manual and Well Design Manual (WDM).
Table 15: Types of Margin
Margin name Types of Margin Function
Safety Margin 1.05 Trip Margin Allow for reduction in effective mud weight caused by upward pipe movement during tripping operations (swab pressure)
5% is taken from EMW
Safety Margin 0.95 Kick Margin Prevent fracture of formation by kick pressure and surge pressure.
5% is added to EMW
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Figure 56 Equivalent Mudweight vs Depth
The figure above shows the pore pressure and fracture pressure profile with proposed casing
seat, while the table explain the margin. To have a better casing design plan, safety margin is
used to keep the mudweight in the safe window. Therefore well can be drilled without
damaging the formation and engineers still have control over the well. According to School of
Petroleum Engineering, UNSW (PTRL5022) safety margin taken at 0.5ppg for trip margin and
also kick margin. In this project trip margin and kick margin is proposed 5% from the
Equivalent Mud Weight. Casing is design based on the operating window (between Trip
margin and kick margin) accordingly except at the depth grater than 1800m, it is because the
mud should not excees 15ppg. The mud density of 15 ppg was the heaviest weight that could
be reasonably held in suspension with the given mixing system, 4000 HHP was the estimated
effective horsepower of all the cementing pumps avaiable, 7000 psi was the highest pressure
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utilizing a 20% safety factor for burst on the existing tubulars. Therefor, to minimize the
problems regarding transporting the mud through the pipe, Equivalent Mud Weight is set at
14.4ppg (depth below 1800m). The following casing intervals are used in the Gullfaks Field:
A. Conductor Casing 30" (100m)
The purpose of running conductor casing is to prevent shallow unconsolidated
formations from washing out or craving-in, which may be caused by circulation of
mud. All conductors for the development wells will be 30" and the hole size is 36".
This conductor is driven into 100 m below the seabed.
B. Surface Casing 20" (100-490m)
Surface casing is the second casing string that will be run in borehole after conductor
casing. The main purpose of running this casing string is to seal off fresh water zones and
to provide structural support to wellhead and BOP equipment. The open hole that has been
drilled for this casing is 26". To determine the formation fracture pressure, leak-off test will
be performed after drilling out surface casing shoe.
C. Intermediate Casing 13 3/8" (490-1600m)
After running this casing in the hole, the next hole size will depend on the weight per foot
of this casing. Lithology and hole problems including weak zones, lost circulation zones,
reactive shale, represent the first factor to be considered before setting the depth of the
Intermediate casing, then mud weight requirement for the next hole section should be
prepared.
D. Production Casing 9 5/8" (1600-2300m)
The setting depth of Production Casing or Liner is generally based on the reservoir
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testing and production requirements. The 12 1/4" open hole has been drilled before
running 9 5/8" production casing. In addition to that, the distance from the reservoir to
the casing shoe depth depends on the depth of the lowest perforation, Completion design
requirements and amount of anticipated perforation debris and sand fill.
Table 16: Casing setting depth and Mud Program
Hole size Casing size Casing setting depth (m)
Casing setting depth (ft)
Mudweight used (ppg)
36” 30” 100 328 6-6.3
26” 20” 490 1608 8-8.3
17 ½” 13 3/8” 1600 5248 10-11
12 1/4” 9 5/8” 2300 7546 14.1-14.4
4.6 Bit Selection
Bit selection design should be conducted after completing casing and drilling fluid design.
4.6.1 Size of Bit
The selection of the bit sizes that will be used to drill a well depends on the well design which
includes the sizes of the holes and casing characteristics (sizes and weights). The casing size
and weight force the bit designers to choose the suitable bit size in order to drill the next hole.
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4.6.2 Type of Bit
Basically, there are three types of drilling bit; Drag Bits, Roller Cone Bits and Diamond Bits.
Drag Bits: are the first bits used in rotary drilling, but they are no longer in common use.
Roller Cone Bits: Roller cone bits (or rock bits) are still the most common type of bit used
worldwide. The cutting action is provided by cones which have either steel teeth or
tungsten carbide inserts. There are two type of this bit; milled tooth bits and tungsten
carbide insert bits, figures 6 and 7. The first one is used to drill soft to medium formations
while the second one is used to drill medium to hard formations.
Diamond Bits: this type of bit is used to drill hard formations. There are three main types
of this bit; Natural Diamond Bits, polycrystalline diamond compact (PDC) bits, and
Thermally Stable Polycrystalline (TSP) diamond bits. This kind of bits is used to drill hard
and very hard formations. Figure 8 shows a (PDC) bit.
Figure 57: Insert Bit
Figure 58: Milled Tooth Bit
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Figure 59: PDC bit
4.6.3 Factors affecting Bit selection
There are two main factors that play a big role on the bit selection. These factors are;
Formation characteristics.
The type of the selected bit depends on the formation hardness characteristics. For
example, long tooth soft bits are used to drill soft formations in shallow depths and
short tooth ones to drill hard formations. Drillibility usually decreases with depth due to
increasing in the rock hardness and overburden. Other factors such as the mud flow
properties and low hydraulic power also make drilling harder at deeper depths.
Generally, milled tooth bits are used for soft to medium formations, insert bits are used
for medium to hard formations while Diamond bits are used for hard and very hard
formations.
Bits are classified according to the International Association of Drilling Contractors
(IADC) code. This code is defined by three numbers and one character. The sequence
of numeric characters defines the “Series, Type and Features” of the bit. The additional
character defines additional design features. The (IADC) bit comparison table is used to
select the best bit for a particular application.
Economic considerations.
The most important factor in bit selection is the drilling cost ($/ft) and the bit cost.
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This cost can be minimized by selecting the best bit that gives less drilling cost. There
are other factors that effect on the rate of penetration (ROP) and the drilling cost such
as weight on bit (WOB), rotary speed and hydraulics. However, the choice of the bit
type can have a bigger impact on drilling costs than the operating parameters.
For all drilling operating, bit selection should be based on a cost per foot of hole drilled.
This provides a bit comparison based on an optimum relationship between penetration
rate, bit footage, rig cost, trip time, and bit cost. Generally, the equation below is used
throughout the industry to calculate the cost per foot of hole for each bit run.
C=B+R (T+t )
F
Where;
C = drilling cost ($/ft).
B = bit cost ($).
R = rig operating cost ($/hr).
T = drilling time (hr).
t = round trip time (hr).
F = hole drilled by bit (ft).
In this FDP, The proposed bits to use for Gullfaks field are Mill Tooth Bits (for soft to medium
formations) and Tungsten Carbide Insert Bits (for harder formations). And the bit sizes have
been selected according to suitable bit clearance. For example, the table below shows the
selected bits. For the lithology hardness, we assumed that the formation hardness is increasing
with the depth due to the beds’ compaction.
Table 17: Bit Selection and Bit size
HoleSize(in)
Casing size (in) Type of lithology*
Formation hardness
Selected bit size (inch)
Bittype
36 30 Almost soft to medium
Driven N/A
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26 20Mainly claystone. Almost soft
to medium 26MilledTooth
17 1/2 13 3/8Mainly claystone poorly
consolidated with siltstone and sand.
Soft to medium 17 1/2
MilledTooth with high
IADC code
At deeper depth 17 ½
13 3/8Claystone/mudstone, Medium
17 1/2tungsten carbide
insert bits
12 1/4 9 5/8Mudstone, siltstone,
sandstone.Medium to
hard 9 5/8tungsten carbide
insert bits
4.7 Drilling Fluid System
Drilling fluid system is critical factor for the drilling process and can effect directly on the
drilling pereformance and drilling cost. The primary objectives of the drilling mud are to
remove the drilled cuttings from the borehole whilst drilling and to prevent fluids from flowing
from the formations that have been drilled into the borehole, additional functions of drilling
mud are to maintain wellbore stability, cool and lubricate the bit. Morever, drillinge fluid
enables bit to enhance drilling activity by providing sufficient hydraulic horsepower.
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Figure 60: Drilling fluid circulation system
In order to achieve drilling mud functions, the optimum density of mud for each hole
section must be estimated based on pressure profile. Mud density must be above the pore
pressure to prevent influx, and less than fracture pressure to prevent formation fracturing and
fluid losses.
There are two most common types of drilling fluid that are always used; water based mud and
oil based mud. Water based muds (WBM) are those drilling fluid in which the continuous
phase of the system is water (salt water or fresh water) and oil based muds (OBM) are those in
which the continuouse phase is oil. There are other types of drilling fluids, i.e. pure gas or gas
liquid mixture (foam). In recent years, the oil based mud has been replaced by synthetic fluids.
WBM has been proposed as a drilling mud for the wells of Gullfaks Field as long as seawater
can be access easily and disposal of them are not hazardous for the environment. According to
the formation types and lithology profile, there are many shale formation sections. These shale
sections may lead to shale reactions if WBM is used. The reactive shale must be treated by
using WBM combines (KCl) with partially–Hydrolyzed polyacrylamide- KCl-PHPA mud.
PHPA helps stabilize shale by coating it with a protictive layer of polymer. It helps to prevent
clay, shale formation from swelling and reducing the possibility of stuck pipe during drilling
operation.
Other additives also can be used to reduce shale reactions such as deflocculant, to avoid
flocculation on the mud system, and Loss Circulation Material (LCM), to minimize the
fliud losses and plug the big porous and permeable holes in the formation. There is
possiblity to add Glycol to reduce torque, increase drilling rate and minimize
environmental impact of drilling operation. In term of additive, weighting and viscous agent
should be used for adequate well cleaning and stability. Chosen additive must be eco-friendly
like using Hematite (Fe2O3) instead of Barite (BaSO4) as weighting material, because its
disposal can settle on seabed.
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The table below shows proposed drilling fluid types and weight at the shoe for each section,
(according to PCSB Well Design), based on the obtained results from the Casing Seat
software.
Table 18: Mud Program
Hole size (in)
Casing size (in)
Mud type Mud @ shoe (ppg)
26 20 Saline WBM 8.3
17 ½ 13 3/8 KCL/PHPA 11.1
12 1/4 9 5/8 KCL/PHPA 14.4
4.8 Casing Cementation
There are many reasons for using cement in oil well operations. The most important functions
of a cement sheath between the casing and borehole are to prevent any movement of fluids
between the permeable zones, to provide support of the wellbore and to prevent any collapse
of the formation inside the reservoir while drilling. It is also gives support to the casing string
being put in place while providing protection against corrosion from the reservoir fluids.
Table 19: Classification of Well Cement
The American Petroleum Institute (API) classifies well cement into nine classes. They ranged
from class A to class H. The selected type of cement is heavily depend on the conditions of the
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well being drilled and the formation temperture at the specific target depth. The API class G
cement is proposed to use in Gullfaks field for wells cementing operations. This type of cement
is selected becaues it is compatible with most additives, reasonable depth and can be used over
a wide range of temperature and pressure. Also, it is considered the most common type of
cement that is being used in most areas.
Table 20: Cement Program
Depth (ft)
Interval
Hole Size (inch
)
Casing Size (inch)
Cement Type
Casing Area (ft)Volume
(ft)Volume (bbls)
Volume excess 15%
0-328.1 328.1 36 30 GConductor
0 0 0
0-1607.6 1607.1 26 20 GSurface 1.916
71.505
52419.556
0 430.9094 495.5458
0-5248 524817 1/2 13 3/8 G
Intermediate 0.8844
0.6947
3645.9310 649.3199 746.7178
0-7546 754612 1/4 9 5/8 G
Production 0.3988
0.3132
2363.6212 420.9477 484.0898
TOTAL VOLUME 1501.17691726.353
4
Table 21: Summary Cement calculation
Depth (ft) Casing Volume (bbls)water (40%) cement (60%) cement (gal)
cement (sacks)
0-328.1 Conductor 0 0 0 0
0-1607.6 Surface 495.545755 198.218302 297.327453 12487.75303 537.0033507
0-5248 Intermediate 746.7178319 298.687133 448.0306991 18817.28936 809.1886041
0-7546 Production 484.0898172 193.635927 290.4538903 12199.06339 524.5890036
Total Volume 1726.353404 690.541362 1035.812042 43504.10578 1870.780958
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From the above table , the total amount of cement being used 7610 sacks with 2809 bbl of total mixwater required.
Wellbore Profile
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100m
490m 537 sacks
1600m810 sacks
Conductor casing 30”36” hole
Surface casing 20”26” hole
Conductor 13 3/8”17 1/2” hole
Figure 61: Wellbore Profile
4.9 Potential Drilling Hazard
There are numerous drilling problems that may occur while drilling even if precautions are considered properly not only to facilities and operation it also brings safety issues to the workers. The most common occurred problems are:
1. Shallow Gas
As mentioned in given data for Gullfaks, potential shallow gas can be confidently interpreted
by using seismic surveys. The only mitigation would be is either drill any pilot hole prior to
opening up and continue with drilling operations or drill with slightly heavier mud that
previously used.
2. Unconsolidated Problems
Stuck pipes could happen when drilling into unconsolidated formation since bond between
particles are weak. Particles in the formations will separate and fall down hole. If there
are a lot of unconsolidated particles in the annulus, the drilling string can possibly be packed
off and stuck.
There are some observable indications of stuck pipe due to unconsolidated formations. One
way is to continue observing the shale shakers if there are unusually high contents of gravel or
sand with increasing mudweight, rheology of the mud and high sand contents in the drilling
mud. Other warning signs include abnormally increasing pump pressure or drilling torque
with losses recorded in the drilling fluid levels in the mud tanks. First mitigation plan is to
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2300m524 sacks
Conductor 9 5/8”12 1/4” hole
circulate at low pressures. Preventive measures would be to use high viscosity mud to aid in
hole cleaning and the drilling mud to be kept constantly at its specification. The ROP should be
controlled at the depths with known lithology of unconsolidated formation.
3. Shale Instability
This hazard could happen when water in the mud is absorbed by shale formations causing
swelling effect on formations. When there is high amounts of water, shale will not be able to
hold their particles together and finally falls apart into the well. This can lead to borehole
collapse and can cause stuck pipes to occur. The mitigation is to maintain a level of clay
inhibitor in the mud during drilling as well as monitoring the shale shakers for unusual
amount of clay.
4. Hole Deviation
Another drilling problem that is a hazard for the drilling operations of Gullfaks field is the
Hole deviation. This issue describes the unplanned departure of the drill bit from a preselected
borehole path. Deviation of the bit from its original and desired trajectory leads to serious
problems such as higher drilling costs. Several following factors may be responsible for this
occurrence:
Heterogeneous nature of formation and dip angle.
Drill string characteristics, specifically the BHA makeup.
Stabilizers (location, number).
Applied weight on bit (WOB).
Hole-inclination angle from vertical.
5. Lost Circulation
Lost circulation occurs when a fractured or the reservoir has high unconsolidated formation
sections, it can also happen if too high mud weight is used and the formation fracture
gradient is exceeded. The complete prevention of lost circulation is impossible. However,
limiting circulation loss is feasible by applying some specific precautions. These precautions
88
include: Maintaining proper mud weight, Minimizing annular-friction pressure losses during
drilling and avoiding restrictions in the annular space.
6. Borehole Instability
Another common type of drilling hazards that may occurs also for the Gullfaks Field is called
Borehole instability. This type of hazard is the undesirable condition of an open hole interval
that does not maintain its gauge size and shape and/or its structural integrity. The causes for
borehole instability include:
Mechanical failure caused by in-situ stresses.
Erosion caused by fluid circulation.
Chemical caused by interaction of borehole fluid with the formation.
Total prevention of borehole instability is not possible because returning the physical and
chemical in-situ conditions of the rock to its original structure is impossible. Though, there are
some mitigation plans that are applicable in order to prevent this occurrence. These plans
include:
Proper mud-weight selection and maintenance
Proper hole-trajectory selection
Use of borehole fluid compatible with the formation being drilled
4.10 Well ControlWell control equipment and training procedures are very important in the drilling phase
through this project. During drilling operations many problems that may occur such as casing
collapse, casing burst, an influx of the formation fluids into the borehole (kick), blow out,
leaking tube, gas filled casing. The kick occurs when the borehole pressure, due to the column
of drilling fluid, has less pressure than the pressure of formation fluids. To prevent the kick, the
borehole pressure should be higher than the formation pressure at all times during drilling. A
kick must be identified earlier before it can reach the surface in order to prevent blowout.
89
Blowouts occur when an uncontrolled kick in the wellbore reaches the surface. It will cause a
lot of problems and it will complicate well control operations, loss of human life, loss of rig
and equipment, loss of reservoir fluids, damage to the environment and huge cost of bringing
the well under control again.
4.10.1 Kick
A kick is a well control problem in which the pressure found within the drilled rock is higher
than the mud hydrostatic pressure acting on the borehole or rock face. When this occurs, the
greater formation pressure has a tendency to force formation fluids into the wellbore. This
forced fluid flow is called a kick. If the flow is successfully controlled, the kick is considered
to have been killed. An uncontrolled kick that increases in severity may result in what is known
as a “blowout.”
The main causes of kick are failing to fill the hole properly when tripping, swabbing in a kick
while tripping out, insufficient mud weight, abnormal formation pressure, loss of circulation,
shallow gas sands and excessive drilling rate in gas bearing sands.
4.10.2 Kick identification
If a kick occurs, and is not detected, a blowout may develop. The drilling crew must therefore
be alert and know the warning signs that indicate that an influx has occurred at the bottom of
the borehole.
There are Primary Indicators and Secondary Indicators that are potential to become a kick. The
Primary Indicators are flow rate increase, pit volume increase, flowing well with pumps shut
off and improper hole fill up during trips. Secondary Indicators are; drilling break, gas cut mud
and changes in pump pressure.
If a kick has been detected in the bottom hole and all the Primary Control precautions are lost,
the kick will reach onto the surface. In this case, Secondary Control precautions should be done
in order to control the uncontrolled fluid flow. The main precautions should be considered are
as follows:
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i. Precautions Whilst Drilling:
Raise kelly above the rotary table until a tool joint appears.
Stop the mud pumps.
Close the annular preventer.
Read shut in drill pipe pressure, annulus pressure and pit gain.
ii. Precautions During Tripping:
Set the top tool joint on slips.
Install a safety valve on top of the string (the valve must be open).
Close the safety valve and the annular preventer.
Make up the Kelly.
Open the safety valve.
Read the shut in pressures and the pit gain.
After these precautions are done, the killing mud should be prepared and pump it into the well
in order to kill the well and control it again.
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4.11 Time Estimation
Seabed 0 0 0Drill 36" hole until 100m 100 1 1Set 30" conductor casing 100 1 2Cement 30" conductor casing 100 1 3Waiting for cement to hardened 100 1 4Drill 26" open hole until 490m 490 2 6Set 20" surface casing 490 2 8Cement 20" surface casing 490 1 9Waiting for cement to hardened 490 1 10
Drill 17 1/2"open hole until 1500m 1600 3 13
Set 13 3/8" intermediate casing 1600 3 16Cement 13 3/8" intermediate casing 1600 1 17Waiting for cement to hardened 1600 1 18Drill 12 1/4" open hole until 1750m 2300 2 20Set 9 5/8" Production casing 2300 3 23Cement 9 5/8" production casing 2300 1 24Waiting for cement to hardened 2300 1 25
Cumulative Duration (Days)
Well Activity Depth,m Duration (Days)
A20
Table 22: Drilling Schedule
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Figure 62: Depth progress vs time for drilling plan of sample well A20
4.12 Drilling Optimization
Drilling optimizations proposed for this reservoir:
Rotary Steerable System (RSS)
For the deviated drilling section, the Rotary Steerable System is preferable compared to
conventional mud motors. The RSS improves the removal of the drill cuttings from the
wellbore and also eliminating the time for wellbore cleanout. A smoother well trajectory will
induce less drag on the drill string as well as the torque required from the surface.
Multilateral Completion
In this study multilateral completion designs were considered as this development only
involves a total of 10 development wells. Application of multilateral wells may be able to
reduce the number of wellhead and size of topside facilities under some options.
Pile Driven Conductor
93
In order to minimize the installation time, drive pipe conductors will be used. The conductor
threads will be rugged and easy to handle. The threads will also be able to stand high torque.
This would allow for deep stabbing and quick connection makeup. The body will be flushed
internally and externally from any restriction to avoid excess drag. Hydraulic hammer will be
used for piling the conductors. The hammer used should have a good power control and can
records the blows and force required for driving conductors. As there will be many conductors
to be piled, the hammer should have no loss of performance after prolonged operation.
Mono-bore Completion
In comparison to slim well, monobore completion will only use single tubular from the
wellhead until the production zone. This method will significantly reduce the drilling time, rig
time and total drilling cost. Due to considerable high risk formation in Galfaks, further study
may be made to investigate feasible applicable of monobore completion in this development.
Cement Assessment Tool (CAT)
The combination of cement and Swell Technology provides a long term isolation for the micro
annulus. The Cement Assurance Tool (CAT) is to be deployed together with the primary
cementing job at the casing pipe. The benefit of the CAT is that it can effectively seal irregular
borehole geometry with complement to all cement slurry design. For highly deviated and
horizontal wells, they often have greater exposure to the reservoir than vertical well, thus
achieving zonal isolation is critical. An incomplete cement sheath surrounding the cement
might occur if casing centralization is less than optimum, drilling cutting removal not
complete, pockets of viscous mud remaining in well.
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4.13 New Drilling Technology Consideration
4.13.1New Drilling technologies
Drilling is the only way to get the hydrocarbon out of rocks; therefore, it plays a major role in
exploration and development of oil and gas fields. New drilling technologies should be
discovered and developed so that it reduces the costs and time of drilling and increases the
drilling efficiency. Worldwide, the research groups have been dealing with several innovative
drilling technologies. Their common aim is to significantly decrease the overall price of the
drilling process, particularly to keep the high constant speed, energy efficiency and shorter
drilling time. There are above twenty innovative non-contact technologies at different maturity
such as: laser, water jet, plasma torch, ultrasonic, microwave, and several others. However few
of them reached Proof-of-the-Concept in laboratory and are currently developed in outside
testing sites.
4.13.2 Jet drilling
According to (Jack, et al. 2008) High-pressure rotary jet drilling holds the promise of increased
rate of penetration with reduced weight-on-bit, torque and vibration levels. A high-pressure
rotary jet drill, pressure intensifier and gas separator have been developed to allow jet drilling
using conventional surface pumping equipment and coiled tubing. High-pressure reaction
turbine jet rotors have been developed for drilling holes ranging from 1-1/8” to 3-5/8”. Jet
drilling tests have shown that 70 MPa (10,000 psi) jets can effectively drill most conventional
oil and gas producing formations. Conventional pumps, swivels and tubing operate at up to 28
MPa (4000 psi). A 2.5:1 pressure intensifier was developed to allow jetting at the pressure
required for effective drilling. The intensifier can operate on two-phase flow using a downhole
gas separator. In two-phase operation the separated gas is used to power the intensifier and the
high-pressure water is provided to the jetting nozzles. The gas exhaust from the intensifier is
ported to the drilling head to extend the range of the jets. Tests have demonstrated that the jet
drilling BHA is capable of cement milling but rates of penetration are lower than a motor and
mill and the pumping pressures required are higher. The tools could find applications in
situations where a motor cannot be used. For example the tools could power a small diameter
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lance jet drill through an ultra-short radius curve for lateral drilling. Well service applications
include removal of hard scale without risk of damage to damage to downhole equipment.
Jet drilling is limited by the threshold pressure required to erode rock and by submerged fluid
jet dissipation. The jet pressure delivered to the rock surface determines the ability of the jet to
cut the rock. The jet power then determines the rate of drilling. The pressure that can be
delivered to a jetting tool through coiled tubing (CT) is limited by fatigue limits of the coil and
the pressure capabilities of available pumps. Approaches to jet drilling at the pressure available
through coil include abrasives, and alternate fluids such as supercritical carbon dioxide or acid.
The consumables associated with these approaches add significant cost and complexity to the
operation. Another approach is to boost the pressure of the jets with a downhole intensifier. A
downhole intensifier has been developed for jet-assisted drilling of 7-7/8” to 8-3/4” holes. The
unit was designed to work with a conventional rotary drill string and to run on drilling mud.
The intensifier area ratio was 14:1 - delivering 84 lpm at 200 MPa from mud supplied at 1260
lpm and 23 MPa. This system provided increased rate of penetration but required higher mud
pressure and the economic benefit was marginal.
A coiled tubing downhole intensifier has been developed to boost fluid pressure by 2:1 to
enable mineral scale milling with standard coil and pumps. A rotary gas separator removes the
nitrogen from the jetting fluid to allow jetting with a straight fluid jet. Dual passage rotary
jetting tools port the nitrogen around the jets to enhance jet range. Jet drilling of oil and gas
producing formations requires a jet pressure of at least 70 MPa. A larger version of this tool
with a higher intensification ratio for rock drilling has been made available as well.
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Figure 63 Jet drill tool
Figure 64: Test well layout
4.13.3 Utilization of laser technology in drilling
One of these technologies is utilization of lasers. Based on (Bazargan, Et al. 2013), LASER is
the acronym for Light Amplification by Stimulated Emission of Radiation. It is generated by a
device which converts energy to electromagnetic beams or photons. These photons are
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produced due to the returning of excited atoms to their lower energy state which releases a
photon. This light radiation is then focused to form intense high powered beams which can
fragment, melt or vaporize a rock.
According to (Sinha. P, 2006) Mechanism of rock destruction is due to ‘Specific Energy’ that
is defined as the energy required to move a unit volume of rock for a given laser system. It has
been found that usually specific energy is lowest for shale followed by sandstone and
limestone. This is an important factor as 70% of formation encountered while drilling consists
of shale. Limestone has a high threshold energy compared to sandstone and shale.
4.13.3.1 Rock spallation
The laser radiations incident on the rocks are reflected, scattered or absorbed. Reflected and
scattered beam are the losses while it is the absorbed beam that is responsible for rock heating
and destruction. Again, the absorbed energy is utilized for fusion (melting), vaporization or
spallation of the rock. It has been found that rock spallation is the most efficient and hence, the
desirable mode for rock destruction.
During spallation, the rock absorbs heat resulting in development of cracks within the rock.
The rock weakens and breaks away. Spallation requires lesser specific energy and rock
removal is easier. For spallation, specific energy is found to be inversely related to specific
power. Rate of penetration is related to specific power and specific energy by following
ROP = SP / SE
Here, the basic difference between SP and SE simply lies in the fact that SP is the power
delivered to the laser system while SE is the amount of energy consumed for spallation of a
given formation. Thus to improve rate of penetration, high specific power and low specific
energy should be used. Laser spallation mechanism satisfies the above criterion and hence is
preferable over conventional methods. Spallation is usually attributed to the thermal stresses
induced in the rock upon lasing. The imperfections or flaws existing in rocks are aggravated
upon application of heat via lasing. The rock fails along these flaw lines and finally spalls as in
the following figure.
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Figure 65: Rock failure due to spalling
Sometimes, in case of thermally conductive rocks, lasing can lead to dehydration of the water
of crystallization associated with minerals present within the rock formation exposed to lasing.
These evaporated vapors expand within the rock volume inducing stresses leading to
mechanical failure and hence promotes spallation. Conditions need to be identified under
which the laser energy will break and remove rock without significant melting as explained by
this figure.
Figure 66 Conditions under which laser removes rock with or without significant melting
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The zone on the left is spallation zone occurring at lower average power. Melting zone is on
the right. Specific energy for spallation is lowest just before melting. At low laser powers,
considerable energy is consumed by thermal expansion, fracture formation and mineral
decomposition leaving little energy left for destruction of rock material. Hence, as power
increases, rock removal gets more effective. Once melting starts, secondary effects begin to
consume additional energy and SE values increase. Therefore, it is desired for the laser to work
within the spallation zone and as close to the transition zone. Black body radiation and plasma
screening effects can affect the magnitude of specific energy while drilling. When rock
temperature becomes high upon lasing, it turns into an intense source of radiation (black-body).
Result, a substantial amount of incident energy is emitted back. Else, ionized gas (plasma) can
form over the surface exposed to laser. This plasma layer formed just above the lased rock
surface reduces the transfer of energy to rocks.
4.13.3.2 Laser based drilling system design
A laser drilling system would require transferring light energy from a laser system placed on
the surface, down a borehole by a fiber optic bundle, to a series of lenses that would direct the
laser light to the rock face. Large hole can be created by overlapped lasing and creating small
holes adjacent to each other. The exact method for getting the laser energy to the bottom of the
hole is the subject of future paper; hence some type of delivery system has to be designed. One
of the basic decisions in designing a laser based drilling system is over the choice of the laser
system. Drilling rate may no longer depend on parameters like weight-on-bit, mud flow rate,
rotary speed, bit design, bore size. Laser parameters like laser type, wavelength, mode of
operation (CW or RP), power density, beam profile can be considered to develop the most
efficient laser drilling system. Near-infrared radiation can be preferred over visible radiation as
availability of high power lasers is in the infrared.
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4.13.4 Utilization of Electrical Plasma for Hard Rock Drilling
Based on (Kogis, et al. 2015) The electrical plasma-based tool changes completely from its
inception the paradigm of the drilling as well as casing milling. The most important advance in
comparison to conventional plasma torch technology is that the electrical arc with temperatures
of tens of thousands of degrees Kelvin heats directly the surface, especially the radiation
component, with minimalized heating of intermediate gas (the intermediate gas flow in
conventional plasma torches reduces the efficiency of heat transfer into the rock). Moreover,
the arc creates area-wide, relatively homogeneous heat flow from spiral arc on the whole
surface for high-intensity disintegration process. Compared to conventional plasma torch
technology, electrical plasma-based technology allows the use of electrohydraulic
phenomenon, generating shock waves for the destruction and transport of disintegrated
material. System also allows obtaining electrical and/or optical characteristics of the arc in the
interaction with the rock to derive indirect sensory information (e.g. online spectroscopy for
logging while drilling.). The technology has been tested on various rock types including
sandstone, limestone, halite, granite and quartzite. Currently, the demonstration prototype is
being tested for drilling of testing borehole in the quarry.
Figure 67 Plasma drilling system
Theory
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The electrical arc with temperatures up to ten thousand of degrees Kelvin heats directly the
surface of the disintegrated material, especially the radiation component, with minimalized
heating of intermediate gas (the intermediate gas flow in conventional plasma-torches reduces
the efficiency of heat transfer into the material).
The heat flow is area-wide, relatively homogeneous by applying long arc on the whole surface
for high-intensity disintegration process.
Rotating spiral arc, in addition to the thermal influence, has “built-in” centrifugal pump
function for disintegrated material removal.
Compared to conventional plasma torch technology, direct electric arc plasma technology
allows the use of electrohydraulic phenomenon, generating shockwaves and pressure waves. It
utilizes generated mechanical power for the destruction and transport of disintegrated material
out of the BHA area.
The pressure waves are generated using high intensity short current pulses. These pulses are
accumulated with a time transformation of charging/discharging from 4 to 7 orders of
magnitude, thus allowing an increase in instantaneous pulse disintegration effect with power
pulses in scale of MW.
The technology is a radical abandonment of the rotary drilling technologies with connected
tubes transferring the torque. Thermal rock-disintegration is a non-contact process, without
vibrations and weight on bit. When drilling using electrical plasma, thermal characteristics
(boiling point, melting point, thermal conductivity) of the rock are determinants for ROP, not
mechanical properties as by mechanical drilling. Based on this feature, drilling in hard rocks
reaches similar parameters as drilling in sedimentary rocks and brings significant benefits in
ROP. The following modes of disintegration are possible distinguishing by plasma
temperature:
● Spallation
● Melting
● Evaporation
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Current drilling technologies either do not, or only to a restricted extent allow performing Real
Time Data Acquisition (RTDA) using spectroscopy. The reason for this comes from the
incompatibility of spectroscopic devices with drilling mechanisms, which means spectroscopy
cannot be carried out unless the drilling string is pulled out of the well for purpose of drill
bit/tool replacement or delivery of a particular rock sample for analysis. Since the continual
information of the rock composition is crucial for the whole drilling process efficiency, a
market demand has emerged and persists for such system. An example of a long-established
approach in exploration is the method of coring, which however, is considerably more
expensive and the degree of automation is small. The technology uses thermal plasma for rock
destruction. For the purpose of the real-time rock analysis and active feedback, the same
plasma source could be employed to provide material excitation to the spectroscopic signal.
The melted and evaporated rock elements are highly excited and produce radiation of relatively
high intensity. This radiation is characteristic and typical for every chemical element present in
a particular drilled substance. Detection of emitted optical signal is guided by optical fibers to
pre-processing by standard analogue spectroscopic module and finally processed on the surface
by spectroscope and sophisticated recognition by adaptive algorithms.
In this way, constant drilling together with rock analysis could be simultaneously achieved,
unlike the traditional drilling systems, which require additional devices sensitive to vibration or
transporting of rock samples to the surface.
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CHAPTER 5 PRODUCTION TECHNOLOGY
5.1 Introduction
5.1.1 Overview
Production Technology is a part in production field of the petroleum industry that deals with
optimizing the production of oil, gas from the reservoir, with the least cost using technology,
which in this case is, the design on the well completion system. Completion design is a mix of
physics, chemistry, mathematics, engineering, geology, hydraulics, material science and
practical hands-on well site experience.
Designing the completion system will need all of this information:
• Design Philosophy
• Well Completion Plan
• Wellhead and Christmas Tree Design
• Inflow/Outflow Performance Predictions
• Artificial Lift Selection
In the consequent sections, a detailed study of production technology in Gullfaks field from the
wellbore to the surface aspects was executed. It is delivered by using WellFlo, Weatherford
company software, to perform Nodal Analysis of each well. Initially, oil and gas production
flows naturally from the reservoir. To assist the production, water injection scheme and gas lift
systems were introduced. Besides, various production problems and their corresponding
remedies are also discussed, along with the design recommendations for different
production/well completion components.
5.1.2 Objectives
The objectives of the production technology design are to:
Analyze the production performance and well deliverability under different factors.
Design a safe and effective well completion for producers and water injectors.
Identify potential production problems and propose solutions.
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Allow future intervention for any production enhancement activities.
5.2 Completion String Design and Philosophy
Design philosophy is the study of assumptions, foundations, and implications of designing the
completion system. Proper completion design is crucial in maximizing recovery and it is so
important to effectively drain out the reservoir fluids to surface, provide subsurface and surface
flow control and safety.
5.2.1 Completion Design
Generally, there are three approaches for completion of reservoir zone, which are open hole
completion, screen or pre-slotted liner completion, and cemented & perforated casing/ liner
completions. Each approach has its applications, advantages and disadvantages, which have
been presented in following table.
Table 23: Comparison between different borehole completion approaches
Type of Completion
Open Hole Completion Screen or Pre-slotted Liner Completion
Cemented & Perforated casing/ liner
Design
Applications Consolidated formations
Low cost / multi well developments
Deep wells,
Inclined/high angles of borehole
Reservoir rock consists of relatively large and homogenous
Wide range of applications
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consolidated with depletion drive
Naturally fractured reservoirs
Some horizontal and multi-lateral wells
sand grains Dependent upon the
screen or slot sizes and the sand particle sizes
Advantages
Less rig time. Eliminate cementing
and perforating cost. Higher production
with less damage.
Low cost technique Prevent any produced
sand Prevent major
borehole collapse Facilitate the passage
of logging tools
Have proper isolation on any hydrocarbon above the targeted sand.
Selective production can be done with SSD.
Disadvantages
Not recommended for wells where distinctive variations in layeral permeability.
Lack of zonal control for production and injection.
Inability for zonal control and may only effectively control sand
Loss in productivity due to slots may quickly become plugged and impede flow
More rig time to cement and perforate target sand.
Small tubular required for perforation.
Coiled-tubing might be required for perforation.
5.2.2 String completion
There are 2 types of production tubing string; single and dual completion string. Single
completion string is a completion string that is only consists on tubing. This is usually used for
one zone completion, or maybe comingled production. As for dual completion string, there are
2 tubing installed inside the bottom hole, giving the option, for example, to produce from 2
different zone, without let them comingle.
Table 24: Comparison of single and dual strings completion
Completion Type Benefits
Dual Strings Completion
Used in applications in which it is desirable to produce two zones simultaneously while keeping them isolated from each other.
Two strings of tubing are run from the surface to the dual packer. One string terminates at the dual packer, and the other string of
tubing extends from the dual packer to the lower single-string packer.
Single String Completion Corresponds to a single zone of fluids from a single wellbore.
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Encloses the tubulars, packers, and other tools which enable the flow path for crude oil and natural gases.
Figure 68: Production Tubing String
5.2.3 Type of completion
There are three types of completion accordingly:
i- Sequential Completions
The simplest form of completion string which is consists of 1 tubing string (single
string) with 1 zone of production.
ii- Commingle Completions Two or more zones are produced at the same time, in the same tubing.
Usually being done for zones which produce the same type of oil/gas, or when
producing gas and oil, but separated on the surface, by separator.
However, this type of completion will make the job much more difficult, and more
costly.
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iii- Selective zone Completions Permits selective production, injection, testing, stimulation, and isolation of various
zones.
Selectivity after completion is accomplished by opening and closing sliding sleeves
between the packers.
5.2.4 Design Philosophy
According to the optimum reservoir simulation outcomes, a total of 7 development wells are
proposed for Gullfaks excluding 3 old producers that have been converted to injectors. The
permeability of reservoir is assumed to be homogenous throughout the production interval.
Since there is only one production interval and the lack of zonal control for production or
injection is also minimized, the single string is suggested. Furthermore, the thickness of pay
zone is adequately high to produce by using vertical well. As presented in Drilling Engineering
Section, due to overpressure and high porosity, high permeability reservoir sands of Gullfaks
field, the formation is weak which will possibly cause sand issues during the production. Sand
grain migrates from the reservoir rock and follows the produced water and oil upstream
causing the production equipment impairment, hence, monitoring in production rates to avoid
damage on the equipment.
Based on several factors and the data discussed, the vertical well completion designed for all 7
single string oil producers is proposed. The production strategy is to produce the oil through
cased hole completion. A sand control screen liner is also installed to prevent the possible sand
problem, which is going to elaborate in detailed subsequently.
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5.3 Wellhead and Christmas Tree Design
The primary purpose of wellheads is to provide the suspension point and pressure seals for the
casing strings that run from the bottom of the hole sections to the surface pressure control
equipment. Wellheads also provide the structural and pressure-containing interface for drilling
and production equipment. They are rated for working pressures of 2000 psi to 15,000 psi (or
greater). They must be selected to meet the pressure, temperature, corrosion, and production
compatibility requirements of the well.
While Christmas tree is the cross-over between the wellhead casing and the flowline to the
production process. It is defined as all the equipment from and including the wellhead
connection through to and including the downstream flange of the choke. A Christmas tree
controls the wellhead pressure and the flow of hydrocarbon fluids and enables the well to be
shut off in an emergency. It also provides access into the well for wirelining, coiled tubing and
logging operations. The tree must be designed to withstand all pressure levels such as gas
lifting, gas injection, and the pressures arising due to a fracture or kill operation.
The design of wellhead and Xmas tree for Gullfaks field complies with the standard
specification of API 6A Latest Edition. “API Spec 6A is an International Standard that
specifies requirements and gives recommendations for the performance, dimensional and
functional interchangeability, design, materials, testing, inspection, welding, marking,
handling, storing, shipment, purchasing, repair and remanufacture of wellhead and Christmas
tree equipment for use in the petroleum and natural gas industries.”
The figure below shows one example of wellhead and Xmas tree.
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Figure 69: Wellhead and Christmas tree
5.3.1 Wellhead
Surface wellhead is installed after casing string is run for specific sections. Inside the wellhead
are casing hangers that suspend the casing and provide annulus seal. Wellhead comprises upper
and lower part. Upper wellhead will be installed and suspends the smaller casing string after
the previous casing string. Main functions of wellhead are:
Suspends casing and tubing string.
Provide support for the Blow Out Preventer (BOP) and Christmas Tree.
Sealing off the various annulus pressure and isolation between casings at the surface
when many casing strings are used.
Provides pressure monitoring and pumping access to annuli between the different
casing/tubing strings.
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5.3.2 Christmas Tree
The basic types of Christmas tree available are:
Table 25: Basic Types of Xmas Tree
Type of Christmas tree Design
1. Single Composite Tree
Used on low pressure (up to 3,000 psi) oil wells, this type of tree is in common use worldwide. The number of joints and potential leakage points make it unsuitable for high pressure, and for use on gas wells. Composite dual trees are also available but are not in common use.
2. Single Solid Block Tree
For higher pressure applications, the valve seats and components are installed in a one piece solid block body. Trees of this type are available up to 10,000 psi, or higher if required.
3. Dual Solid Block Tree
For dual tubing strings, the solid block tree is the most widely used configuration. The valves controlling flow from the deeper zone, the long string, are the lower valves on the tree. While there are some exceptions to this convention, unless the tree is clearly marked it can be assumed that the valve positions reflect the subsurface connections.
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The design for the Christmas tree of Gullfaks field is listed as below
Table 26: Xmas Configuration
Components Configuration
Active wing valve Hydraulically operated
Lower master valve Local and remote operated
Upper master valve Hydraulically operated
Kill wing valve Local and remote operated
Swab valve Local and remote operated
Additionally, there are two categories of Christmas tree which are dry tree and wet tree. For
dry tree production, the wells are essentially extended to a surface platform where personnel
have ready access to the production tree for operations, maintenance and inspections. While in
wet tree production, the production tree is located on the sea floor, thousands of feet under
water. The following tables present the summary on various features and benefits vs challenges
of Dry Tree & Wet Tree accordingly, in order to be selected in Gullfaks development well.
Table 27: Summary of Dry Tree vs Wet Tree*
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Table 28: Benefits vs Challenges of Dry Tree & Wet Tree*
Benefits Challenges
Dry Tree
Tree and well control at surface in close proximity of people
Drilling conducted from the facility – reduced CAPEX
Direct vertical access to wells for future intervention activities
Minimal offshore construction
Enable future drilling and expansion
Safety concern due to well access at surface
Large vessel payloads due to the need for supporting risers
Require high cost vessels such as Spar, TLP due to design sensitivity to vessel motions
Complex riser design issues
Limited by existing riser tensioner capacity
Riser interface with vessel require speciality joints, e.g. keel joint, tapered stress joint
Heavy lift requirement for riser installation
Wet Tree
Tree and well access at the seabed isolated from people
Full range of hull types can be used
Low cost hull forms are feasible
Simplified riser/vessel interfaces
Drilling and workover will need a separate MODU or require hull with drilling/workover capability increasing the overall CAPEX
Potentially large vessel payloads due to risers
Flow assurance may be a challenge due to potentially long tie-in
High spec pipe-lay vessels required to install risers and flowlines
*retrieved from SPE presentation
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5.4 Material Selection
Conductor, surface and intermediate casing are used for structural integrity, which
typically requires significantly larger diameters and heavier weights than tubing. Moreover,
casing is not expected to come into contact with the produced fluids. Thus, approximately
entire casing and liners are commonly made from carbon steel, while there is a small
section of casing that is exposed to reservoir fluids and should generally be made of the
same material as that selected for the tubing. This section is referred to as ‘exposed
casing’ or ‘exposed lining’ and is cemented in place for well bore integrity in some well
designs and also perforated and used for production in others. Therefore, material
selection for casing and tubing is essential for Gullfaks development plan estimated 10 years of
production.
Classifying materials which can be safely deployed is the main focus of the material selection
process. Selection will be determined by parameters associated with the production and
shut in environments, for instance, temperature (e.g., bottom hole and shut in), pH,
chloride concentration, and H2S partial pressure. Particularly, cost considerations, lead
time, quality assurance, and schedule are also influenced factors into the material selection
process.
Reservoir fluids flowing through the production tubing are often corrosive, making necessary
the use of corrosion resistant alloys (CRA) offshore. CRAs contain various quantities of Ni,
Mo, Cr, Cu, and other elements for corrosion resistance, making them significantly more
expensive than carbon steel (CS). Commonly, CRAs can be categorized into four groups in
increasing order of corrosion resistance and cost: Martensitic stainless steel (MSS),
duplex and super duplex stainless steels (DSS and SDSS), super austenitic stainless
steels, and high Nickel Alloys. With the exception of the API 5CT L80 13Cr steel, all
other CRA casing and tubing alloys are proprietary. As can been seen from Corrosion
Resistant Alloy Selection Process, the appropriate material is chosen based the on presence
of elemental sulfur and a combination of H2S partial pressure, chloride concentration and
temperature.
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Referred to DST report, no CO2 and H2S were detected from the Gullfaks field. From PVT
data, there is low content of CO2 and no any H2S presence in the production fluid. Corrosion
Resistant Alloy Selection Process shows that required material for Gullfaks is Martensitic
Stainless Steel. The other completion accessories are suggested to use the same material as
production tubing to avoid galvanic corrosion due to dissimilar metals.
Figure 70: Corrosion Resistant Alloy Selection Process*
*Retrieved from http://www.gateinc.com/gatekeeper/gat2004-gkp-2014-08
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5.5 Perforation Techniques
In cased hole completions (the majority of wells), once the completion string is in place, the
final stage is to provide the communication path between the well-bore and all desired zones.
These activities are known as perforation, which use explosive charges to produce holes
through the wall of the casing, the cement sheath and penetrate into the formation, thereby
allowing oil or gas to flow to the surface as well as evaluating and optimizing production
rate/injectivity from each zone.
Perforating is accomplished by using a perforating gun - loaded with shaped charges - that is
lowered into the well and detonated in the wellbore.
5.5.1 Shaped Charged Characteristic and Performance
The basic shaped charge consists of a conical liner, a primer explosive charge, the main
explosive charge, and charge case or container, which is illustrated in the following figure.
Figure 71: Shaped Charged Components
The main explosive charge is extremely powerful in energy releasing specific energy per unit
weight of explosive. Detonation of the main charge is complete after only 100 -300 micro
seconds. This fast reaction time is of importance in that it concentrates the detonation energy of
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the exploding charge to very limited target area. The impact pressure caused by the jet is
approximately 10 to 15 million psi. This pressure overcomes the casing and formation strength
and forces material radially away from the jet axis. In addition, a conical liner concentrates the
explosive force so that it provides maximum penetration of the target over a limited area.
Depends on the shape of conical liner that gives different effects into the formation (See Figure
below):
(a) A flat ended charge spreads the force of the explosion over a wide area of the target with
very limited penetration.
(b) A conical shaped charge concentrates the force of the explosion and provides greater
penetration.
(c) If the conical cavity is lined with a metallic liner, the penetration is greatly increased by a
lined conical cavity.
Figure 72: The importance of using a conical liner in a shaped
Furthermore, charge container can be either a metal or a disintegrateable case e.g. ceramic. The
force of the explosion on a specified target area is directly assisted by a metal case. The angle
of the cone and the liner material determines the penetration depth and the perforation's
diameter (for a given charge weight). A copper liner gives a wide diameter hole (< 1.0 in.) as
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used for sand control or popped hydraulic fractured completions, while a deep penetrating
charge (~ 0.5 in. diameter) uses a sintered metal liner. The display below is an example.
Figure 73: Picture demonstrates the angle of the cone and the liner material determines the
penetration depth and the perforation's diameter
5.5.2 Spacing
Spacing in perforation system is the distance between the perforations, and is affected by
perforation density and phasing. Spacing of each charge should be sufficient in order to avoid
the mutual overlapping of the elastoplastic stress areas in the vicinity of perforations during oil
and gas production and prevent the sloughing and failure of single perforation from leading to
a chain reaction, thus avoiding the sloughing and sand production of the whole perforating
section. In addition, when having larger perforation spacing, it will cause smaller mutual
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interference between perforations, thus, result in lower perforation density. Furthermore, sand
migration and production may be generated because the flow rate of single perforation for low
perforation density is high. Shot density that indicate by shot per foot (spf) and phasing also
affect stability of perforation tunnel.
Figure 74: Perforation Charge Arrangement
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5.5.3 Gun size
The gun size to be used for the perforating activity must have the size that is almost near the
casing size and with a minimum gun clearance of ½ inch. For instance, to perform the
perforation in 7-inch casing, the 5-inch casing gun will be used for the execution. Moreover,
the size of the perforating gun will dictate the maximum explosive load which can be
accommodated in the charges.
5.5.4 Conveyance Methods
In general, there are two types of conveyance method, which are tubing conveyed perforation
(TCP) and wireline conveyed perforation. However, TCP is much more favorable than the
wireline, because TCP has its advantages as following:
The ability to use large charges at high shot densities; creating perforations with a long
length and with diameter entrance holes (negative skin) completions.
The perforating operation can be completed in one run even for long intervals. Intervals
in excess of 1,000 m have been shot in one run.
The well is not perforated until after it has been completed and it is safe to allow well
fluids to enter the wellbore.
Perforating can be done either in underbalance, balance/slightly overbalance, and extremely
overbalance.
i. Underbalanced Perforating
High flow capacity formations where perforation may be a choke on flow.
Natural completions in thinner zones with high reservoir pressures
Where later operations will be underbalanced
Competent sandstones (some exceptions; cavities for instance)
Where the best possible test is needed
ii. Balanced / Slightly Overbalanced Perforating
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Only when the wellbore fluid is non-damaging and low particulate.
When fracturing – note that high overbalance may make breakdown more
difficult.
When perforation tunnels can collapse at the slightest underbalance
iii. Extreme Overbalanced Perforating (EOP)
EOP is a process that breaks down perforation by high pressures generated by
high gas pressures or gas generating charges.
Where perforation breakdown is very difficult or expensive (pumping
equipment).
Where permeability is low (<1 md) and typical perforation with underbalance is
not effective.
Where permeability is high (k >100 md) and no fracturing planned, but damage
bypass is needed.
Figure 75: Results of underbalanced, balanced and overbalanced perforations
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5.5.5 Perforation Design
After considering different perforation parameters, the consequent table summarizes suggested
perforation designs for Gullfaks field planning. It is benefit in achieving successful perforation
performance, providing ideal communication path between the well-bore and all desired zones
and obtaining the optimum production rate from each zone.
Table 29: Summary of the perforation system selected
Parameters Selection Justification
Perforation Density (spf)
12 Low flow rate of single perforation, low fluid velocity, low sand
Phase 30 Provide more efficient flow characteristics
Charge Type Big Hole Provide mechanical stability, big hole that make the gravel packing process become efficient, and because of the sand formation that easily can cause the tunnel to become smaller.
Penetration Depth <10ft
Perforation Diameter
8-10 times size of the
particle
Best effectiveness
Conveyance Method
Tubing Conveyed Perforating
(TCP)
Since it will be going to be overbalance perforation, this is suitable for overbalance perforation; that withstand high pressure.
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5.6 Well Completion Plan
5.6.1 Summary
To achieve successful well completion for Gullfaks field, the following option has been given:
Table 30: Well Completion Option for Gullfaks field
Completion Parameters Options Tubing size Range from 2-3/8” to 5-1/2” Type of completion Single String Tubing material Carbon steel, Low Alloy Steel or
Corrosion Resistance Alloy (CRA) Completion Cased holePerforation Tubing Conveyed Perforating Artificial Lift Gas Lift Sand Control Gravel Pack
5.6.2 Well Completion Matrix
A total of ten wells are proposed for Gullfaks which consists of seven oil producers and three
water injectors. Sand control method selection will be mentioned in Sand Control Section of this
report. The conceptual well completion matrix is summarized in table below based on the
location of the well.
Table 31: Well Completion Matrix for Gullfaks Field
Well Name Type Description Remarks
A10 SS Cased hole, TCP Perforation
Gravel Pack
Oil Producer Well
A15 SS Cased hole, TCP Perforation
Gravel Pack
Oil Producer Well
A16 SS Cased hole,TCP Perforation
Gravel Pack
Oil Producer Well
A19 SS Cased hole, TCP Perforation
Gravel Pack
Oil Producer Well
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A20 SS Cased hole,TCP Perforation
Gravel Pack
Oil Producer Well
B9 SS Cased hole, TCP Perforation
Gravel Pack
Oil Producer Well
C5 SS Cased hole,TCP Perforation
Gravel Pack
Oil Producer Well
B8 SS TCP Perforation, Inject water into
acquifer
Water Injector Well
C4 SS TCP Perforation, Inject water into
acquifer
Water Injector Well
C6 SS TCP Perforation, Inject water into
acquifer
Water Injector Well
5.6.3 Proposed Completion Schematic
Well schematic is a tool string design with configuration of completion components and
tubing. The selection of components is varying with the tubing size which is essential to take
into account to make sure that the selective components will provide the continuous flow path
with minimum flow restriction that happen due to components’ groove profile.
The design the basic tool string is assumed that all wells having the same conditions. The
following proposed schematics diagram consists of single string oil producer and single string
water injector. The selection components must be based on tubing size.
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: WEIGHT: : 310 PPF: : 133 PPF: : 68 PPF: : 43.5/47 PPF: 130 m :: XXX m-AMSL : -
: XXX m
Flow Coupling
TR-SCSSSV
Flow Coupling
GL Mandrel
GL Mandrel
GL Mandrel(GLV Dummy)
Sliding Sleeve(Closed)
13-3/8" shoe Casing setting depth
Sliding Sleeve (Closed)9-5/8"sump packer
8.313" Bore XN Nipple
POP AssemblyEnd of Tubing
9-5/8"sump packer
Proposed by Ngo Nguyet Tran -Group 1
TD at XXX m-MDDF
9-5/8" shoe
RESERVOIR (Oil Producer)
Sand Interval: XXX - XXX m-MDDF
Perforation Method: TCP
Gravel Packed
(Depth TBC) Liner
(Depth TBC)
(GLV Orifice)
(GLV Unloading)
(self-equalizing type)
TBC
IN INEQUIPMENT
MIN ID MAX OD
Note: All depths are in meter from Sea BedDEPTH LONG STRING
m-MDDF (OIL PRODUCER)
DRILL FLOOR TO THF
WATER DEPTH LINERMAXIMUM DEVIATION 55-60 deg PRO. CASING 9-5/8" 2300m-MDDFPBTD ? m-MDDF INT. CASING 13-3/8" 1600 m-MDDF
TBC
WELL NAME: XXX Oil Producer
LOCATION / SLOT: GULLFAKS Block 34/10
PROPOSE COMPLETION SCHEMATIC
DATE OF COMPLETION SIZE DEPTHRIG CONDUCTOR 30" 100 m-MDDFTD XXX m-MDDF SUR. CASING 20" 490m-MDDF
DRILL FLOOR HEIGHT TUBING TBC
Figure 76: Single String Oil Producer Tubing
125
: WEIGHT: : 310 PPF: : 133 PPF: : 68 PPF: : 43.5/47 PPF: 130 m :: XXX m-AMSL : -
: XXX m
Flow CouplingTR-SCSSSVFlow Coupling
13-3/8" Casing setting depth
9-5/8" Hydraulic Packer
8.313" Bore XN Nipple
POP AssemblyEnd of Tubing
9-5/8" shoe
WELL NAME: XXX Injector
LOCATION / SLOT: GULLFAKS Block 34/10
PROPOSE COMPLETION SCHEMATIC
DATE OF COMPLETION SIZE DEPTHRIG CONDUCTOR 30" 100 m-MDDFTD XXX m-MDDF SUR. CASING 20" 490m-MDDFPBTD ? m-MDDF INT. CASING 13-3/8" 1600 m-MDDF
WATER DEPTH LINERMAXIMUM DEVIATION 55-60 deg PRO. CASING 9-5/8" 2300m-MDDF
DRILL FLOOR HEIGHT TUBING TBC -
Note: All depths are in meter from Sea BedDEPTH LONG STRING
DRILL FLOOR TO THF
m-MDDF (OIL PRODUCER)
MAX OD
IN INEQUIPMENT
MIN ID
TBC
(self-equalizing type)
13-3/8" Hydraulic Packer
(Depth TBC) Liner
WATER ZONE
Interval: XXX - XXX m-MDDF
Perforation Method: TCP
TD at XXX m-MDDF
Proposed by Ngo Nguyet Tran -Group 1
Figure 77: Single String Water Injector Tubing
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5.6.4 Completion String Design and Accessories
The production strategy is to produce the oil from single zone through open hole completion
with packer isolating the casing and tubing in order the fluid to flow only through the tubings.
Following are the design for the downhole completion:
i. Single tubing string of 3-1/2” ID is proposed at this moment. It may be changed upon
the Nodal Analysis to meet the required targets.
ii. For well control, tubing retrievable SCSSV is proposed for completion. Retrievable
vales are preferred as it is easier to maintain and to be replaced when broken, while O-
rings of the valves may be permanently damaged during production/well intervention
campaign.
iii. Flow coupling, X-Nipple and XN-Nipple will be installed as per standard practice for
oil producer. Nipple is to ease the future well intervention campaign. In addition, No-go
nipple (XN Nipple) is to avoid any wireline tools from dropping off the string. Flow
coupling is to protect from internal and external erosion caused by high velocity &
turbulence flow.
iv. Three Gas lift mandrels (GLM) with dummy valves will be installed to enable future
installation of gas lift valves.
v. Gravel pack is installed in order to prevent or control the sand production.
vi. For safe measures and double barrier precaution, single hydraulic retrievable packer
will be used for single string oil producers. The hydraulic packer will act to prevent
communication between the different sands. Hydraulic packer is recommended for
deviated or horizontal well because no tubing movement is required to set the packer,
thus this is important during well completion. Communication is only allowed by
opening the sliding slide doors.
vii. As for the water injectors, a higher grade of hydraulic packer or permanent packer is
required for internal isolation in order to overcome any temperature and pressure
change should the cold injected water and hot oil produced will influence the downhole
thermodynamic and pressure systems.
viii. In the future, gas conning is highly expected to breakthrough in the horizontal section
due to the thick gross volume of gas cap (150m) above the producing oil zone. Future
127
zone change activities are expected, so that gas conning problem can be control.
Because of that, XD-SDD (wireline control SSD) cannot be used due to high
inclination angle (>80 degree) of horizontal section. Hence, hydraulic surface control
SSD is suggested to achieve an effective reservoir management campaign and to ease
the future well intervention activities.
ix. It is necessary to periodically monitor reservoir pressures in order to determine if all the
reservoir units in Gullfaks are behaving as one pressure system or not. The installation
of Permanent Downhole Gauge (PDGs) as an improved well monitoring system in
selected wells will provide the pressure data when required. Re-evaluation of reserves
status, reservoir drive mechanisms and development strategies depend heavily on
correct knowledge of reservoir pressures.
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5.7 Inflow/Outflow Performance Prediction
5.7.1 Nodal Analysis
Using the data from the Reservoir part of well test, the completion can be designed using the
concept of finding the optimum tubing size for the completion and allows to determined flow
potential or deliverability of the wells by finding the common value of the production rate for
inflow and outflow (IPR and OPR) as well as bottomhole pressure (BHP). Furthermore, based
on the Production Technology notes (2010), it is stated that, an estimation of the expected
production rates at various times in the field's life is the proper way to design the tubing string.
This is because by gaining the information on these volumes, required size of the production
can easily be estimated.
Hence, NODAL Analysis approach will be used as it is an analytical tool that used to enhance
well production by optimizing well completion design. This approach views the total
producing system as a group of components which includes all the components upstream and
downstream such as separator, surface choke, well bore pressure and reservoir pressure. By
doing this, completion design to suit reservoir deliverability and any restriction that may exist
in the system can be identified thus improving production efficiency. An improper design of
any one component, or a mismatch of components, adversely affects the performance of the
entire system.
Additionally, node can be select anywhere in the production system as it can be as reservoir,
wellhead or at the wellbore. Then, all the components upstream of the node comprise the
inflow section, while the outflow section consists all of the components downstream of the
node. A relationship between flow rate and pressure drop must be available for each
component in the system for the analysis to be made. Nodal analysis is performed on the
principle of pressure continuity, where there is only one unique pressure value at given node
regardless of whether the pressure is evaluated from the performance of upstream or
downstream equipment.
129
The performance curve (pressure-rate relation) of upstream equipment is called inflow
performance curve and the performance curve of downstream equipment is called outflow
performance curve. The intersection of the two performance curves defines the operating point,
which is operating flowrate and pressure, at the specified node.
5.7.2 Base Case Model
The models for well development were generated using PROSPER, a production simulation
software from Petroleum Experts, based on available data from exploration and appraisal wells
of Gullfaks field. Well A20 is used for the analysis with some assumptions are made to
represent the whole reservoir, for instance, permeability and water depth were taken as average
value; reservoir properties (oil gravity, GOR, gas gravity, etc..) were made with well test and
associated with Petrel value; tubing ID is 4.052”; cased hole completion; and so on …
The data will be coming from the test point data of the well test report. The main flow data
consist of the following:
Reservoir pressure
Well test production data
Wellhead pressure
Reservoir layer pressure for the interested zone
Bottomhole temperature
Mid perforation depth
Effective permeability (assume Darcy skin equal to zero)
5.7.2.1 Inflow Performance Relationship (IPR)
Vogel model is used in the construction of Inflow Performance Relationship Curve shown the
figure below. Calculated productivity index (PI) based on data given is 3.36 stb/day/psi
generates an absolute open flow (AOF) of 4834.7 stb/day for matching with the development
plans (See Figure Base Case IPR for Gullfaks Field. The Glaso correlation is used for the gas
solution, bubble point pressure and formation volume factor, while Beggs et al has been chosen
130
to represent the vertical flow correlation for Gullfaks field. All the correlation mentioned above
yield a high accuracy during the matching process compared to the other correlations.
Figure 78: Base Case IPR for Gullfaks Field
5.7.2.2 Operating Point
Operating point is the point where the IPR curve intersects with Vertical Lift Performance
(VLP) at specific pressure and flow rate at a given condition. The operating point of the
Gullfaks well was constructed using Prosper as well. The simulation result is show bellowed.
The natural flow for the base case model can be predicted from the intersection between the
inflow performance curve and outflow performance curve shown in the following Table.
Table 32: Base Case Calculated data from Prosper
Productivity Index, STB/day/psi 3.36
131
Absolute Open Flow, STB/day 3384
Operating pressure, psia 1570
Producing capacity, STB/day 1910
Figure 79: Base Case Nodal Analysis
132
5.7.3 Water Cut Limits
As seen from the values of the table, the greatest oil production rate will be at its initial state
whereby reservoir pressure is 2516 psia with 30% of water cut. As the reservoir pressure
depletes, it is shown that the oil production decreases. Similarly, increasing percentage of
water cut for the same reservoir pressure will still decreases the oil production rate. Increasing
fw will increase total liquid density, GLR decreases because gas comes from the oil phase.
Thus, hydrostatic component increase causes BHP increases with water cut, ultimately shifted
the intersection point to the left.
With a water injection scheme in place, it is expected to face even more severe water
production from Gullfaks. One way of dealing with such a problem is to plug-off “watered-
out” perforations. The advantages will be prevent, reduce or isolate water production, hence no
need to dispose water, which results in cost-saving and increases flowing pressure, allowing
higher flow rates at upper zones. Stability of zones also increases. However, there are
disadvantages such as if cement plug is set it could damage the formation, reducing
permeability and increase the skin effects, and thus, reduces production. Solutions that are
injected in plugging operation can reduce hydrocarbon flow out of producing formation.
Plugging off operation is costly and time consuming.
Table 33: Effect of water cut on various reservoir pressures
Oil Production Rate (STB/d)
Reservoir Pressure
(psia)
2516 2400 2300
Wat
er C
ut
(%)
30 1910 1700 1520
40 1825 1605 1430
50 1712 1485 1310
60 1553 1345 1150
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5.7.4 Tubing Selection
Tubing is one of the important component parts in the production system of a flowing well and
is the main channel for oil and gas field development. It is a tube used in a wellbore through
which production fluids are produced (travel). So, the size of the tubing should be selected,
carefully and according to the condition of the well. This is to ensure that the energy
consumption for lifting and the longest flowing time from the wellbore to the surface can be
utilized rationally and efficiently. Since size will affect much on the production, proper tubing
size must be used because going undersize and oversize can lead to different cons. If it is
undersize, the flow velocity will be excessive, thus, the increase of friction between the
flowing fluid and the wall of the tubing and result in the tubing will limit the production rate.
Contrarily, oversized tubing may lead to an excessive liquid phase loss due to slippage effect
or an excessive downhole liquid loading during lifting. In order to tackle this matter, sensitivity
analysis of tubing size should be carried out using the nodal analysis method.
The intersections of the TPR curves and the IPR curve are just the production points under the
various tubing sizes. In general, increasing the tubing size will increase the production rate of a
flowing well, as shown in Figure below for reservoir pressure of 2516 psia. However, when the
tubing size exceeds the critical size, the increase in tubing size may lead to a decrease in
production rate.
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Figure 80: Sensitivity analysis on tubing size for reservoir pressure 2516psia
It can be observed from table below, the optimum tubing size is 5.5” OD with 4.767” ID. As
discussed earlier, if the tubing size exceeds this critical size, the increase in tubing size may
lead to a decrease in production rate. This is because it increases friction & consequently
pressure drop decreases up to a certain point. Therefore in this completion tubing with 5.5”OD
can be chosen.
There are two main factors in choosing the most optimum production tubing size. Firstly, the
tubing size that is selected must have a lower pressure drop due to friction and turbulence. So
since larger tubing size will yield lower frictional flow, it will cause lower pressure drop, and
thus, maintain an optimized oil production rate. Second factor will be the water cut. The aim is
to get high oil rate. This means we should increase of tubing size. However, by this, we need
135
more energy to lift up the oil, so need high water cut (so that energy needed is less). But this
water cut can't be too high to avoid excessive water production.
Table 34: Different tubing sizes with different reservoir pressure
Oil Production Rate (STB/d)
Reservoir Pressure
(psia)
2516 2400 2300
Tu
bin
g ID
(in
ches
)
2.992 1495 1260 1125
3.548 1575 1525 1370
3.954 1880 1675 1490
4.052 1910 1680 1505
4.767 2125 1870 1700
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5.7.5 GOR Sensitivity
As shown in below table for 2 phase (liquid + gas), GOR has more effect than any other
variables GLR increase, liquid holdup decreases hence there will be decrease in hydrostatic
component. However, total rate is increasing, and friction loss component depends on rate
squared. One of the best methods is using gas lift to increase GLR but up to certain point only.
The table also shows that beyond GOR of 6000 scf/stb the production rate will decrease.
Table 35: GOR values with different reservoir pressure.
Oil Production Rate (STB/d)
Reservoir Pressure
(psia)
2516 2400 2300
GO
R (
SC
F/S
TB
)
1000 1910 1700 1520
2000 2175 1950 1770
3000 2300 2075 1890
4000 2355 2130 1950
5000 2370 2150 1965
6000 2360 2140 1960
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5.8 Artificial Lift Selection
5.8.1 Selection Criteria
Artificial lift is defined as any method used to raise oil to the surface through a well after
reservoir pressure has declined to the point at which the well no longer produces by means of
natural energy. Artificial lift is essential in wells when there is inadequate pressure in the
reservoir to lift the produced fluids to the surface, but often used in naturally flowing wells
(which do not technically need it) to increase the flow rate above what would flow naturally.
The produced fluid can be oil, water or a mix of oil and water, typically mixed with some
amount of gas.
The most common of artificial lift are: rod pumps, electrical submersible pumps, hydraulic
pumps, progressive cavity pumps, gas lift. Selection of most economic that yields optimum
production is very crucial to the success of production development phase. All five artificial lift
are compared according to different well condition show in tabulated form below.
There are several artificial lift methods available, but due to certain constraining factor, only
gas lift and Electric Submersible Pump (ESP) is been considered to be install in this well. Main
consideration is offshore located well and it is currently producing solution gas together with
the oil production. These automatically rule out rod pump and hydraulic pump.
Gas lift valve can be used to a useful life of 10-20 years compared to the ESP which can last
for only 3-6 years before they are required to be changed and maintained. Nevertheless, ESP
may be the best artificial lift method in the world at current stage where almost 70% of the
world oil productions are from the utilization of ESP. However the productions are most often
for high production well ranging from 1000-64000 stb/day. Since for Gullfaks wells, we are
producing at the rate approximately 2000-3000 stb/day per one well, it would not be
economical for ESP utilization in the field since there is higher capital and maintenance cost
involved, where having gas lift on site would be sufficient to produce.
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Table 36: Artificial lift methods and its features
Well
Condition
Rod Pump PCP Gas Lift ESP Hydraulic
Pump
Design
Operating
Depth
Fair Fair Good Fair Very good
Operating
Volume
To 6,000
BFPD
To 4,500 BFPD
To 30,000 BFPD
To 40,000 BFPD
To 15,000 BFPD
Temperature To 550 F To 235 F N/A To 400 F To 550 F
Service Workover or
Pulling Rig
Workover or
Pulling Rig
Wireline or
Workover
Rig
Workover or
Pulling Rig
Hydraulic or
Wireline
Scale Fair Fair Fair Poor Fair
Sand Fair Good Very good Fair Poor
High GOR Poor Fair Very good Good Fair
Deviation Poor Fair Very good Good Very good
Paraffin Poor Good Poor Good Poor
Corrosion Good Fair Fair Fair Poor
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5.8.2 Gas Lift Design
5.8.2.1 Design Basis
Using the gas lift method, gas injected reduces the density of the produced fluid assisting the
fluid flow from the reservoir through the tubing to the wellhead. The gas is injected through
gas lift valves, which are run in side pocket mandrels together with the tubing string, and is
designed so that only one valve is open passing gas at one time. The purpose of injecting gas
into the tubing is to decrease the density of the flowing gas liquid mixture and therefore
decreasing the required flowing bottomhole pressure.
There are two types of gas lift. One of it is continuous flow gas lift. The main feature in the
continuous flow gas lift is merely to lighten the gradient in the liquid column so that the
reservoir pressure available will be adequate to cause flow to occur or to increase.
Alternatively, the other type of the gas lift maybe used when reservoir will not produce in a
continuous manner. This method is called intermittent gas lift because a column of liquid is
allowed to accumulate in the bottom of the well and then a large volume of gas is quickly
injected below this column to lift it to the surface. This cycle is repeated at an experimentally
determined optimum combination of fill-up time, the liquid column lifting time and volume of
gas injected. As a reservoir depleted, it may become necessary to consider gas lift as primary
artificial lift to maintain economic oil recovery.
The main concerned in gas lift design is the specification, facing and pressure setting of the
unloading and operating valves in order to initiate and maintain oil production with economic
gas injection rate. After design installation, a primary concern in the daily operation of gas lift
is the cost of the gas compression facilities. This can be uneconomic if the excessive gas
volumes are circulated due to shallow injection depth or if excessive volumes are circulated
with diminishing returns. The first of these is due to faulty design. The latter is due to improper
operation of even a correctly designed system.
Gullfaks field development is in appraisal phase so most of the variables are not available even
in the Gullfaks previous well test data. As it is stated in the given proposal that Gullfaks well
will start using gas lift after 4 years of production then the production string must prepare for
gas lift operation by including the Gas Lift Mandrel (dummy) in tubing string design. For
140
Gullfaks gas lifting system, side pocket mandrels with dummy valves will be installed initially
in the production string. When gas lift is required, the dummy valves can be replaced with gas
lift valves using wireline. The aquifer support is estimated to be weak and gas lift will be
required after 4 years of production in the case of high water production.
5.8.2.2 Production Analysis by using Gas Lift Method
The design developed by Prosper software consists of three Valves, where the operating valve
is located at the lowest desired position accordingly:
Valve 1 (24/64th inch) located at 1136.79m MD
Valve 2 (32/64th inch) located at 1572.51m MD
Valve 3 (operating valve – 34/64th inch) located at 1699.07m MD
Under natural flow depletion without any support from artificial lift, at 30% water cut, oil
production rate is about 1910 STB/D while gas production rate is 1.91MMscf/d. By installing
continuous flow gas lift with the proposed design above, Prosper simulator demonstrates that
oil production rate can be increased to approximately 2117 STB/D by injecting 1.5 MMscf/D
gas into wellbore (as shown in below table). Additionally, this amount of gas is taken from
available produced gas to inject back into the well as cost saving. Therefore, Gas Lift is
proven to be the best method to be installed as artificial lift in Gullfaks field.
Table 37: Comparison on production before and after installing Gas Lift
WC Oil (stb/d) Water (stb/d) Gas (MMscf/d) 30 1910.64 818.845 1.91 No Gas Lifted
30 2117.32 907.421 2.331.5 MMscf/d of
Gas Lift Injected
141
A clear comparison on benefit of Gas Lift on Oil rate under various water cut conditions (30-
80%) is illustrated in following graphs.
Figure 81: Oil rate at different water cut without Gas Lifted
Figure 82: Oil rate at different water cut with Gas Lifted
142
Furthermore, as illustrated in following graph, the higher amount of gas is injected, the higher
oil production rate obtained. However, the increment is up to an optimum point, whereby if the
injection rate is beyond this limit, it will have reverted effect, the production rate will be
decreased. In this case, maximum gas lift injection rate is 7.5 MMSCF/D to produce
approximately 2250 STB/D.
Figure 83: Oil production influenced by various gas lift injection rate
143
5.9 Sand Control
5.9.1 Sand Failure Prediction
Sand formation is a natural activities or properties in a formation that cause the unconsolidated
sand from the formation to enter the wellbore, and sometimes, being produced together with
the oil; sand production. The key factor in sand production is the formation failure which is
governed by in-situ stresses in addition to the mechanical properties of the rock. Stresses
around wellbore / perforations are more concentrated and weak rocks (unconfined compressive
strength less than 1000 psi) are prone to deformation under these conditions. In addition,
drilling and perforating contribute to damage in the near wellbore region of the formation. The
fluid production and the associated drag force applied on the weakened formation induce
erosion at sandface and sand grains are transported up the wellbore.
The two key processes in the physics of sand production are:
i. Stresses acting on the rock surrounding the wellbore must exceed the strength of the
rock so that it fails.
ii. Transport (fluid flow) is required to move sand from the failed zone into the production
system.
Rock will not fail due to fluid flow alone. Rock only fails as a result of stresses acting in the
near wellbore area. These stresses are caused by the pressure difference between the formation
and the wellbore (that is, drawdown and/or depletion), fluid frictional forces and the tectonic
forces acting through the formation (weight of overburden, and horizontal stresses). When the
magnitude of the combined forces exceeds the strength of the formation, the rock will fail, and
sand may be produced. In the failed zone a highly plastic state must prevail for the drag forces
introduced from fluid flow to move sand from the formation into the well. The implication is
that there will be a critical flow rate or drawdown pressure below which sand will not be
produced. If this rate is below a desired production rate, some form of sand control is
necessary to maintain well integrity.
144
The following depiction is an example of potential sand production occurrence where the failed
zone around a perforation tunnel and providing the source of sand production is highlighted in
red. The radius of the failure zone can be several times the radius of the opening depending on
the rock strength, stress and flow conditions.
Figure 84: Potential Sand Production
5.9.2 Problems Caused by Sand Flow
Sand production causes severe issues and several integrity challenges. In high rate gas wells,
especially in a subsea completion environment, sand production leads to serious and dangerous
erosion because of the velocity of the sand grains striking the tubulars and/or surface facilities.
Sand production in water injectors is also an issue especially where cross-flow can occur.
Cross flow generally occurs from low permeability to high permeability layers in water
injection wells after shut-in. However, since low permeability sands typically will have higher
rock strength, they may not produce sand. Sand is also restricted from flowing out of the
perforation cavities due to sand bridging. This bridging will tend to break down dependent on
a large number of variables, including; perforation geometry, sand size, well angle, wettability
factors, capillary forces, differential pressure and flow rate. Among these factors, wettability,
145
capillary forces, and in situ stresses tend to prevent movement of particles and enhance sand
bridging.
On the other hands, in low PI wells, some companies advocate deliberately inducing sand
production to stabilise the formation. This removes near wellbore formation damage which
can result in a significant increase in PI. Recent experience in the North Sea on one platform
showed that sand production increased PI by up to 120% in some wells and by 40% on
average. However, this process demands a rigorous approach to sand surveillance monitoring
and well monitoring, surface handling and disposal of sand and represents a high risk strategy.
5.9.3 Sand Control Consideration and Design
5.9.3.1 Sand Management
Sand management requires an understanding of the mechanisms that cause sanding and the
development of a field-validated methodology to predict the critical conditions for sand
production. Nowadays, sand management solutions call for an integrated, multi-disciplinary
approach that draws on the skills of geologists, petrophysicists, reservoir and production
engineers. It involves the integration of laboratory core tests, well log and field test analyses,
sanding records, water and hydrocarbon production analyses, the use of predictive modelling,
well performance modelling and, perhaps most importantly, sound engineering judgement.
Quantifying sand transport and erosion risk is primary information for well management
optimisation against sand production. If the sanding evaluation indicates a high risk of sand
production, then solids transport models are used to assess whether it will it be lifted to surface
or settle over perforation. If it settles over the perforation, downhole sand control will usually
be required. If it is lifted to surface, the tubing and surface facilities erosion rates can also be
modelled to assess tolerable flow rates.
The combination of sand failure and transport/erosion models are vital to the decision whether
sand exclusion (downhole) sand control or sand production can be effectively managed by
more passive means, such as: oriented perforation; selective/deferred perforation and
selective/deferred shut off; and well management/operational procedures (e.g. bean up rates). If
146
these passive measures cannot guarantee well integrity or productivity, then sand exclusion
downhole will be required. The decision on the optimum form of sand control involves
analysis of many technical and economic factors.
5.9.3.2 Sand Control Design
Sand control can be done either passive or active. But majority will apply passive sand control,
which involves accepting sand production, choke management, selective perforation, oriented
perforation and well preconditioning. However, passive sand control may arise other issues as
it may reduce the well productivity, cost to maintain surface and downhole equipment is high
due to erosion and passive approach may lead to loss of the well. Other optimal selections for
completing sand-prone reservoir actively, is by physically restrain sand movement or known
also as sand exclusion.
a) Sand Control Method
Figure below shows various types of mechanical sand control that can be used.
Figure 85: Various types of mechanical sand control method
147
Consideration:
Reduction of Drag Forces-Flow rate per unit area, if applicable, should be given first
consideration. Increase flow area if possible. Good well completion practices are
paramount.
Gravel Packing-This offers the only practical sand control for long zones. Gravel
packing may also be most practical for short zones-but remedial work, multiple
completions, small hole diameters, and abnonnal pressures increase difficulty and cost.
Open hole gravel pack should always be used on single completions where water or gas
shut-off or other change of completion interval is not anticipated.
Inside casing, gravel pack restricts productivity-but productivity may be maximized by
a sufficient number of large clean perforations and effective placement of the gravel.
Resin Consolidation-This is used in short zones where, for one reason or another, a
gravel pack cannot be used. Some of the applications are: small pipe diameter, top zone
of a dual completion, offshore or isolated location where tubing hoist is not available
and abnormal formation pressures make through tubing work advisable.
Resin Sand Pack-This has most of the same problems and advantages of the inside
casing gravel pack.
b) Gullfaks sand control recommendation
As discussed earlier, due to overpressure and high porosity, high permeability reservoir sands
of Gullfaks field, the formation is weak which will feasibly cause sand issues during the
production. Thus, here is some suggestion to monitor the sand production problems as briefly
listed below:
Acoustic sand detectors should be installed on all production wells corresponding to
topside on all pipelines. The sand detectors were designed to report estimated amounts
of produced sand.
Completed using gravel pack.
148
c) Design Procedure
As for the gravel size, some method should be used in order to get the get the information to be
used for gravel pack selection. The best method is to use the laser particle size analysis (LPSA)
and particle size distribution (PSD). This is because; the LSA can evaluate, calculate the media
size diameter and grain size distribution. The, using the PSD using the LPSA result proper
gravel and screen size can be determined. Tips from Saucier said, optimum gravel sand size is
obtained when the median size of the gravel sand is no more than six times larger than the
median size of the formation sand.
The chart below shows a typical sand analysis distribution. Ten percentile sand size is defined
as the point on the distribution scale where 10 % by weight of the sand is of larger size and
90% of smaller size.
Figure 86: Typical sand analysis distribution
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A uniformity coefficient, can be calculated as Cu = D 40D 90
, where D40 is the 40 percentile size
and D90 is the 90 percentile size (D90):
- Cu< 3 well sorted, highly uniform sand
- 3< Cu< 5 uniform sand
- 5 < Cu< 10 moderate/poorly sorted sand
- Cu > 10 poorly sorted non- sorted sand
According to Tiffin criteria, the sorting coefficient is taken into account where Cs= D10D 95
- Cs< 10 (well sorted) Cs>10 (Not well Sorted)
Percentage fines content is defined as ‘fines’ that can pass through 44 microns gravel particles
pore size.
Cs< 10 => standalone screens
Cu< 3 and fines < 2% => wire-wrapped screens
3 < Cu< 5 and 2% < fines < 5% => mesh screens
Cs>10 or Cu> 5 or fines > 5% -gravel pack, can utilize slotted liner
As for the screen, the size of the screen to be chosen need to be smaller than the smallest grain
size in the formation. This is to ensure that no or less sand particle can be prevented from
entering the wellbore. Proper selection can be done based on the following table
Table 38: Screen gauge used with various types of gravel size
Gravel size
(US Mesh)
Gravel size
(in.)
Screen Opening
(in.) (micron)Screen Gauge
40/60 0.0165-0.0098 0.008 ~200 8
30/50 0.0230-0.0120 0.010 ~250 10
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20/40 0.0330-0.0165 0.012 ~300 12
16/30 0.0470-0.0230 0.016 ~400 16
12/20 0.0660-0.0330 0.020 ~500 20
8/12 0.0940-0.0470 0.028 ~700 28
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5.10 Potential Production Problems
In this section, the potential production problems occurrence during the operation, such as
formation damage, skin, flow assurance issues, are going to be explained while the
recommended monitoring or mitigation strategies are also proposed accordingly.
5.10.1 Formation Damage
Formation damage is defined as “A reduction in the natural capability of a reservoir to produce
its fluids, such as a decrease in porosity or permeability or both”. It usually occurs near the
wellbore (within a feet of wellbore), however damage sometimes can penetrate deeper into the
formation depending on formation properties and damage mechanism. This reduction in
permeability can be due to a multitude of causes, but in all cases it will reduce the natural
productivity due to the imposition of the extra pressure drop as the fluid flows to the wellbore.
Formation damage can occur throughout the life of the well from the moment that the drill bit
penetrates the formation. All well activities need to be evaluated for their potential for causing
formation damage, including: Drilling, Cementing, Perforating, Production, Injection. The
following sections will discuss about the various sources of formation damage as well as the
techniques by which formation damage can be stopped.
5.10.1.1 Drilling Operations
When over balance drilling (Wellbore Pressure > Formation Pressure) is conducted, pressure
balance required between the drilling fluid and the reservoir pressure to keep the well under
control will results in these mud particulates being forced into the formation. A filter cake will
be formed on the surface of the wellbore and some particles will also invade into the formation.
These solids will not easily flow back into the wellbore when the pressure gradient has been
reversed. Thus, formation damage has been created.
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The solid particles in the drilling mud have a size which is good enough to form filter cake on
the borehole wall. The permeability of this filter cake and the formation influences the rate at
which the mud filtrate invades the formation. From figure below, it shows the typical
relationship between drilling fluid type, cost and the risk of formation damage. It is realized
that using oil based mud (OBM) helps in reducing the risk of damage but costly. Thus, it is
suggested to design an appropriate mixing mud for the drilling operation.
Figure 87: Typical relationships between mud type, cost & risk of formation damage
5.10.1.2 Cementing
The success of casing or liner cementation in turn means the removal of mud cake. This
removal of the mud cake triggers the fluid loss i.e. filtrate from the cement slurry. This cement
slurry filtrate is highly reactive to any kind of formation clays due to its highly alkaline nature.
It also has a high concentration of calcium cations which can lead to precipitation of calcium
carbonate, calcium hydroxide (Lime) or calcium silicate. Also, cement slurries have a very
high natural fluid loss unless controlled by suitable additives. Another form of formation
damage is when natural fractures are present in the formation making the fluid loss control
additive ineffective. Moreover, some reservoir formation is naturally fractured, thus, the
cement slurry flows through these fractures may cause some blockages within it.
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Proper fluid loss control is necessary since excessive dehydration of the slurry will lead to
failure of the cement job, use of fluid loss control additives may help overcome this problem.
The depth of cement fluid loss is less since the filtrate volume is limited and hence can be
bypassed by the perforations. To avoid natural fractures being clogged, changing the
completion design to open hole is the simplest way. But this causes hindrance to integrity of
the hole and in extreme cases it may collapse.
5.10.1.3 Perforation
Perforation operations cause pulverization and compaction of the rock around the perforation,
which can reduce the permeability of the rock surrounding the perforation. As shown in the
figure, the damage region around the perforation is about ¼ to ½ inches in thickness with
permeability of the zone being 7% to 20% of the undamaged permeability. This deleterious
effect can be minimized by perforating with sufficient underbalance pressure, or sometimes
with extreme overbalance.
The “cleaning up” process is often attributed to the progressive removal of perforating debris
(charge debris, rockfragments and the low permeability crushed zone); all of which reduce the
well inflow. This removal increases the transmissibility between the well and the formation.
Figure 88: Damage area during Perforation
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5.10.1.4 Production
Typical production formation damage phenomena that lead to such reduction in well
productivity are; fines movement, use of incompatible workover fluids, inorganic and organic
scale formation and bacteria.
5.10.2 Well Stimulation
The earlier discussion was focused on the various types of formation damages which are
expected to take place during different processes throughout the life of the well. Consequently,
various well stimulation techniques have listed down in subsequent table, which help to
overcome formation damage.
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Table 39: Available Stimulation Techniques
Despite its benefits, in contrary, well stimulation can also causing formation damage unless
proper thought is given to fluid selection:
Reaction products generated by the reaction between the injected acid and the
formation rock may precipitate, causing a reduced permeability (formation damage).
The acid may weaken the rock, by attacking the intergrain cement so that (normally
temporary) sand production is observed when the well is returned to production.
The above deconsolidation process may generate “fines” which can migrate and block
pore throats.
Acid can be incompatible with crude oil leading to formation of a solid “sludge” which
can block pores or a viscous acid / oil emulsion formation.
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A further form of acid/crude oil incompatibility is the formation of a highly viscous
water/oil emulsion.
5.10.3 Flow Assurance Issues
5.10.3.1 Corrosion
Corrosion problem is one of the nightmares in oil and gas industry (Nalli, 2010). Based on
PVT report given, the Gullfaks field has 0.91% mole percent of CO2 in its wellstream and CO2
content is 0.08-1.49% in the production. Carbon dioxide has been determined as one of the
main corroding agent in the oil and gas industries. This is due to the fact that CO2 will dissolve
in water and form acid, which in turn reduce the pH value of the flowing fluid and create a
corrosive environment in the pipelines.
Corrosion monitoring is a very important step because we will know the corrosion condition in
the pipeline from time to time and take any precaution and maintenance steps if necessary.
Recent technology enables the pipelines to be monitored using intelligent pigging operations
like magnetic flux or ultrasonic pigs. These pigs will inspect the internal condition of the pipe
such as the wall thickness and corrosion condition besides carrying out the normal pipe
cleaning operation. Since prevention is always better than cure, regular pipeline shutdown and
turnaround operations shall be carried out to check the condition of pipelines and also
equipment like separators, drums and heaters. If the condition is below the safety level, the
equipment or pipelines must be either repaired or replaced to prevent any accident form
occurring.
Several common materials for pipeline manufacturing and their characteristics will be listed in
the table below. However, it should be noted that this list only serves as a general guidance
because there are still many other factors that we need to consider before making the selection
of material. They include detailed study of the flow regimes and patterns, flowing environment
such as pressure and temperature, corrosion mechanism involved and also the duration or
lifespan expected for the particular pipeline.
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Figure 89: Possible well design for CO2 injection (from Cooper, 2009).
Table 40: General Material Specification and Characteristic
No.
General Material Specification
Application Use in Hydrocarbon Industry
End Use in Hydrocarbon Industry
Oil and Gas Application
1 C- Mang-Silicon Steels (Carbon Steels)
General purpose, medium corrosion, medium temperature up to 200°C. Also low temperature up to -45°C.
Pressure vessels, Heat exchangers, Tanks, Spheres and Piping
Bulk fluids, crude pipelines, flow lines. Water and steam injection lines. Production and test separators, KO drums,
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storage tanks.
2 C- Chrome-Moly Steels (Low and Medium Alloy Steels)
Medium corrosive and high temperature up to 600°C media application. An economic compromise between CS/SS.
Furnace tubing, Heat exchangers, Re boilers, Pressure vessels, High temperature piping.
Well head items, chokes, manifolds and well components with sour and high temperature application.
3 Straight Chromium Steels (Chromium >12% and <18%)
Highly corrosive and very high temperature medium up to above 800°C application.
Furnace/ Heater tubing, High temperature vessels, Columns, High temperature heat exchangers
Christmas trees, well heads, downhole rods, valves and casing pipes.
4 Chromium- Nickel Steels (Stainless Steels: Chromium> 18% and Nickel >8%)
Highly corrosive, high temperature medium up to 800°C and strong oxidizing medium.
Pressure vessels, Columns, Heat exchangers, Alloy claddings, Piping & Cryogenic applications
Valve trims, instruments and internals of separators and tanks, low chloride levels.
5 Nickel Steels (2.5%/ 3.5%/ 9% Nickel)
Mildly corrosive and very low temperature media up to -100°C.
Cryogenic storage vessels, Heat exchangers, and piping especially for LNG applications.
Rarely used in oil and gas sectors except for LNG storage tanks, piping and pumps.
6 Duplex Stainless Steels (22% Chromium: Duplex; 25% Chromium: Super Duplex)
Saline and highly chloride concentrated media and moderate temperatures up to 60°C.
Pressure vessels, Exchangers, Piping with saline and chloride environments.
Piping, vessel and tank internals where very high level of chloride is present.
7 Nickel- Chrome (Inconels: Nickel-Chromium-Iron)
High corrosive, high temperature, high chloride and high sour media.
Piping, Tubing, Instruments normally for high temperature and high sour environments.
Well head and flow lines, manifolds with high sour and temperature applications.
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8 Nickel- Iron (Incoloys: Nickel-Iron-Chromium)
High corrosive, high temperature, high chloride, high sour environment
Piping, Tubing, Instruments normally for high temperature and high sour applications.
Well head and flow lines, manifolds with high sour and temperature applications.
The following table shows general monitoring methods for corrosion.
Table 41: General Monitoring Methods for Corrosion
Method Measures Comments
Coupons Average corrosion rate by weight loss. Pitting rate by pit depth measurement.
Must be positioned where corrosion is occurring.
Spools Pattern of attack. Pitting rate by pit depth measurement. May be able to weigh.
Very useful in surface systems. Not as easy to remove as a coupon.
Linear Polarization
Instantaneous general corrosion rate. Requires conductive fluid (water). May have problems in sour systems.
Potentiodynamic Polarization
Estimate pitting and general corrosion rates.
Used primarily for corrosion inhibitor evaluation.
Electrical Resistance
Change in electrical resistance of corroding element. Gives general corrosion rate.
Not normally used in sour systems due to conductivity of iron sulfide.
Galvanic Probe Current generated by bimetallic couple.
Primarily used for O2 detection.
Hydrogen Probe Hydrogen generated by corrosion of probe. Rate of pressure increase is proportional to corrosion rate.
For sour systems. Must be temperature compensated.
Hydrogen Patch Probe
Hydrogen generated by corrosion of pipe wall. Gives hydrogen permeation rate.
Used only in sour systems.
Dissolved Gas Analysis
O2, H2S, CO2 Presence of H2S in sweet system indicates sulfate reducing bacteria.
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Corrosion Product Analysis
Indicates which dissolved gas is responsible for corrosion.
FeS will oxidize to iron oxide on exposure to air.
Dissolved Iron Amount of iron dissolved by corrosion.
Not quantitative in sour or oxygenated systems. Must subtract any “natural” iron.
Inhibitor Concentration
Concentration of inhibitor present in fluid.
Helpful to determine inhibitor distribution in system.
Bacteria Counts Number of bacteria present. Related to corrosion rate.
Mechanical Calipers
Internal corrosion in tubing or casing. Pitting or general.
Scale or corrosion product may mask pits.
Electromagnetic Induction
Measures wall thickness and ID of casing.
Does not detect small holes or isolated pitting.
Ultrasonic Scanning
Measures ID in tubing and casing. Some tools also measure wall thickness.
Response is attenuated by scale buildup.
Magnetic-Flux-Leakage Pigs
Detects both internal and external attack in pipelines. General or pitting corrosion.
System must be built to accept tool. Reserved for large systems due to cost.
Ultrasonic Pigs Measures both ID and OD of pipelines.
Line must be filled with liquid.
Wire-line Pipeline Inspection
Tools
Measures both ID and OD of pipelines.
Maximum inspection length is a little over a mile.
Ultrasonic Inspection
Thickness of metal. Presence of pits or cracks.
Very localized measurement.
Radiography General or pitting corrosion. Particularly useful in locating pitting corrosion in piping and wellheads.
Visual Inspection
Pattern and severity of attack. Extremely reliable but often inconvenient.
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5.10.3.2 Emulsion
An emulsion is a dispersion (droplets) of one liquid (dispersed phase) in another immiscible
liquid (continuous liquid). Crude oil is usually produced along with water, generally
commingled production with water causes emulsion formation. Crude oil emulsions form when
oil and water (brine) come into contact with each other, when there is sufficient mixing, and
when an emulsifying agent or emulsifier is present. Emulsions can be difficult to treat and may
cause several operational problems in wet-crude handling facilities and gas/oil separating
plants. The presence of emulsion will lead to a number of problems including:
Create high-pressure drops in flow lines
Lead to an increase in demulsifier use
Sometimes cause trips or upsets in wet-crude handling facilities
Results in corrosion and catalyst poisoning in downstream processing facilities.
However, it is believed that any serious emulsion problem is not anticipated from new wells in
the early stage of the production period. To reduce the emulsion tendency of the Gullfaks
crude, it is suggested to inject demulsifiers, which are chemical compounds that widely used to
destabilize, and assist in coalescence of crude-oil emulsions.
5.10.3.3 Asphaltenes
Asphaltenes is known as amorphous, bituminous, solid material which precipitates from some
crude. It is made up of a complex mixture of asphaltenes, resins and maltenes which were
originally present in the crude oil under the original reservoir conditions as a metastable
colloidal dispersion. The precipitation process is triggered by pressure reductions – asphaltenes
precipitation is often first observed near the bubble point such that the change in crude oil
composition due to the removal of some of the lower molecular weight species from the crude
oil destabilizes the colloidal dispersion that maintained the asphaltenic material in suspension.
The effect of composition and pressure on asphaltene precipitation is generally believed to be
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stronger than the effect of temperature. Particularly, when CO2 injected into the oil reservoir it
will contribute to the asphaltene precipitation by composition change. However, there is no data
as to how much asphaltene by weight presence in the crude oil.
5.10.3.4 Hydrates
Hydrate is a snow like substance formed by the combination of free water, gas that might occur in
production lines and chemical lines where has relatively high pressure and ambient temperatures
well above the normal freezing point of water at elevated pressure. In Gullfaks field, the gas
production is high, there may probably create hydrates plug. Hence, hydrate prevention and
control are important for flow assurance of Gullfaks field development. It can be achieved by
proper insulation or injecting methanol at the wellhead as well as carrying out sequential
pressure build-up/pressure depletion of the area.
5.10.3.5 Wax/Paraffin Deposition
In many production systems wax would tend to deposit on the pipe wall during production.
Wax is made up of long-chain (>18), normal or branched with some cyclic and aromatic
hydrocarbon with the composition CnH2n+2 (Freund et. al., 1982). The wax deposition depends
on the fluid composition and temperature. Production cases where low fluid temperatures
occurs in the pipeline, where wax both deposits at the wall and precipitates as particles
suspended in the oil. Both diameter reduction due to the wax layer at the wall and the effect of
suspended wax particles on oil viscosity may significantly increase pipeline pressure drop and
thereby reduce the production capacity of a pipeline. Precipitated wax may cause fluid turning
non-Newtonian with an increase in viscosity.
When further cooled enough and at “right conditions” the precipitated wax could form a gel.
This temperature is called the Pour Point. The solid wax is dissolved in the crude oil at
reservoir temperatures and forms a crystalline precipitate when the flowing fluid temperature
reduces below wax appearance temperature (WAT) or when flowing fluid temperature greater
than wall temperature (Toil > Twall); in other words, Twall < TM < WAT. The temperature
difference between the reservoir temperature and WAT ranges from only a few degrees
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centigrade to many tens of degrees. Wax precipitation is highly dependent on the temperature.
However, pressure changes only have a minor effect on the value of the wax appearance
temperature.
The wax deposition can lead to various severe matters, such as increasing the fluid viscosity,
higher pressure loss and pump pressure, restriction of flow within tubing, pipelines and process
equipment, affecting the accuracy of monitoring equipment, failure to restart in the case of
severely plugged pipelines and difficult separation process as the wax crystals provide
emulsion stabilization.
From DST and PVT data of Gullfaks field, there is no indication of wax content. But after a
period of time, have been observations of pressure build-up in pipelines due to wax precipitation.
Because the oil produced from Gullfaks field is waxy, and wax can precipitate at low temperatures.
Therefore measurement shall be taken to avoid wax accumulation. Consequently, if there is
wax presence in future, the wax mitigation strategies will be as follows:
Prevention:
Insulation
Active Heating DEH
Hot Oil Circulation
Chemicals
Diluents
Remediation
Pigging
Coiled Tubing
Chemicals
Sacrificial Spools
Self-Insulation
Shear Stripping
Soak and Cough
Chilling Systems (Cold Flow Slurry) Prevention
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Insulation
Active Heating DEH
Hot Oil Circulation
Chemicals
Diluents
Remediation
Pigging
Coiled Tubing
Chemicals
Sacrificial Spools
Self-Insulation
Shear Stripping
Soak and Cough
Chilling Systems (Cold Flow Slurry)
The below table exhibits advantages and disadvantages of two common mitigation strategies
for wax deposition issues:
Wax Table 42: Comparison of two common mitigation strategies for wax deposition
Mitigation Strategies
Insulation Heating
Applications Use of flowline/riser insulation to ensure arrival above WAT
Types of insulation External coatings Pipe-in-pipe Buried pipelines
Heat desired portion of systems Localised heating Heating medium
circulation Internal hot oil fluid
circulation Type of heating:
Active (direct) heating
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Indirect heating
Advantages
Common practice No operating expenses
No risk of gel formation Active system
Disadvantages
Initial CAPEX cost Potentially difficult to
provide sufficient insulation:– WATs from 65°C – 75°C– long tiebacks– cold environment
CAPEX increases to allow for infrastructure to be included
Circulation temperature must be sufficient to ensure arrival temperature
5.10.4 Other Production Problems
Some of other potential issues that can be encountered in the wells and the common techniques
to encounter them can be referred at the Production Appendices.
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CHAPTER 6 FACILITIES ENGINEERING
6.1 Introduction
6.1.1 Overview
The functions of offshore production facilities are very much the same as those described for
land operations. An offshore production platform is rather like a gathering station;
hydrocarbons have to be collected, processed and evacuated for further treatment or storage.
However, the design and layout of the offshore facilities are very different from those on land
for the following reasons: (1) A platform has to be installed above sea level before drilling and
process facilities can be placed offshore. (2) There are no utilities offshore, so all light, water,
power and living quarters, etc. also have to be installed to support operations. (3) Weight and
space restrictions make platform-based storage tanks non-viable, so alternative storage
methods have to be employed.
This section will describe the facilities required to accommodate the production of fluids from
the Gullfaks field. It also involves the design of other production support system, incorporating
operation and maintenance philosophy. In general, facilities engineering covers all aspects of
equipment and system design right from the well head to its final delivery point. This
development considers safety issues, cost effectiveness and economical values. The design
philosophy of the development is based on 7 well producers and 3 injection wells.
6.1.2 Problem Statement and Objectives
Design selection for the Development, Engineering Design Consideration, and Surface
Operation Facilities and Platform Utilities suitable for the Gullfaks field with economic
and environmental considerations.
Implementation of Operation and Maintenances (O&M) philosophy of the facilities and
its abandonment options.
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6.2 Design Basis and Philosophy
In order to build the best platform design, the following factors are considered:
Offshore environment: Structure will be located in exposed and hostile environment.
Thus, reliable source of information on local winds, wave and current stability plus
with stability of the structure play an important role in determines safety measure of the
platform. Apart from that, facilities design should minimize environmental impact and
damages to the environment.
Economic Justification: Besides aiming for a high hydrocarbon recovery, platform
design should consider economic side of it. The equipment’s capacity and sizing should
not be over-designed, but maintained to an optimum performance according to the field
capacity. Miscalculation in designing will cause an unnecessary money outflow and
increase in overall cost.
Processes: The design of filters, vessels, separator, and pump must be specifically abide
the type of fluids produced and properties of the fluid. The produced fluid must
undergo primary separation and necessary treatment before evacuated to the onshore
facilities. The factors affecting behavior of the fluid flow, temperature and pressure of
the fluid and material of the pipe that can withstand it need to be considered.
Design Flexibility: Future consideration must be taken into account during current
design to reduce cost for renovation. Additional slots must be allocated for potential
development based on production forecast that has been done.
Safety Measures: Safety has always been the top priority in oil and gas industry in
general and specifically in highly-risk working environment of plants and platforms.
The need for a safe working condition and measures are a lot far exceeding the need of
hydrocarbon production as the impacts caused by failures in safety aspects are
catastrophic. The safety measure are HSE plan, safety personnel, safety equipment,
backup facilities, emergency procedures, multiple stage failure containment and
emergency shutdown system. These are all been looked into prior to installation to
safeguard the nature of operation and most importantly the personnel on board.
Geological Consideration: Sea floor topography and formation profile will influence
the platform design. Gullfaks, North Sea Field is located in shallow marine water, so it
is highly possible for the platform to be fixed rig.
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6.2.1 Design Basis
Several design factors are looked into consideration for several reasons which are safety issue,
to ensure the platform built will be reliable and economically viable and facilities design that
will be able to withstand the volume of oil produced for certain period of time. The
geographical data of Gullfaks Field:
Location : 175 km from Mongstad Oil Terminal (Bergen, Norway)
Water Depth : 130-230 meters
Number of wells: 7 production wells and 3 injection wells.
The production forecast profile for Gullfaks Field is as below:
Figure 90: Production forecast profile for Gullfaks Field
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6.2.2 Reservoir Data
Referring to Table below, Gullfaks fluid is a non-problematic in nature. The fluid can be
classified as black oil. Flow assurance is a key part in assessing the technical viability of this
project. Specific issues addressed are fluid flow (line pressure drop and flow patterns), wax
mitigation and corrosion control.
Two design philosophies are strongly adopted for the Gullfaks field. They are:
1. Selecting the optimum Facilities, through cost optimization
2. Following safety guidelines at all times
Table 43: Reservoir and Fluid Properties of Gullfaks Field.
Oil Gravity (˚API) 64.2
Viscosity (cp) 1.33
Highest Composition C1+ with 36.47 mole %
Oil Saturation (% PV) 77.4
Formation Type Consolidated Sandstone
Temperature (˚F) 220
Depth (ft) >5000
Several other factors also have to be considered while designing the facilities system. They
include the following:
1. The offshore location of the Gullfaks field
2. The required production facility services with regards to the field's oil recovery
mechanism
3. Processing facilities required for fluid handling
4. Properties and Phase behaviour of the produced fluid
5. The man power required to operate the facilities.
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6.2.3 Rig selection
The type of rig which will be selected depends upon a number of parameters, in particular:
cost and availability
water depth of location (offshore)
mobility/transportability (onshore)
depth of target zone and expected formation pressures
prevailing weather/metocean conditions in the area of operation
experience of the drilling crew (in particular the safety record)
Figure 91: Types of offshore drilling rigs
Considering the water depth of Gullfaks reservoir and the sea conditions, we have chosen Jack-
up rig as mentioned in the drilling section of this report. Jack-up rigs are either towed to the
drilling location (or alongside a jacket) or are equipped with a propulsion system. The three or
four legs of the rig are lowered onto the seabed. After some penetration the rig will lift itself to
a determined operating height above the sea level. If soft sediment is suspected at seabed, large
mud mats will be placed on the seabed to allow a better distribution of weight. All drilling and
supporting equipment are integrated into the overall structure. Jack-up rigs are operational in
water depths up to about 900ft and as shallow as 15ft. Globally, they are the most common rig
type, used for a wide range of environments and all types of wells.
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6.2.4 Platform selection
The water level in Gullfaks field is approximately 130-230 meters only which is considering as
shallow marine water. Therefore, the platform is chosen based on platform effectiveness, cost
and suitability to the production and facilities required. This criteria provided is to ensure the
smoothness of the production as well as occupying facilities that are needed to be installed on
it. Some aspects that are taken into account after predicting production forecast on production,
the fluid properties and flow rates and economical factor of the development plan.
Selection of the type of platform depends on several factors:
1) The depth of water
2) Sea conditions and environment
3) Production life of the wells
4) Cost of the platform system
5) The distance from the shore
A platform is a large mechanical structure which facilitates the activities related to drilling and
production of hydrocarbons. Offshore platforms can be split broadly into two categories: fixed
and floating. Fixed platforms are generally classified by their mechanical construction. There
are four main types:
Steel Jacket Platforms
Gravity-Based Platforms
Tension Leg Platforms (TLPs)
Minimum facility systems.
Floating platforms can also be categorised into three main types:
semi-submersible vessels
ship-shaped monohull vessels (such as floating production, storage and offloading
(FPSO))
SPAR platforms.
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Therefore a fixed platform would be most suitable and economical. But detailed study is
carried out to be certain. Fixed platforms are built on concrete or steel legs which are anchored
onto the seabed to support the deck consisting of drilling rigs, production facilities and
accommodation deck for crews.
Figure 92: Type of Oil Platform
Based on the water depth and sea conditions, the feasible alternatives for our Gullfaks field
production platforms seems to be either steel jacket platforms or gravity-based platforms.
1. Steel piled jackets are the most common type of platform and are employed in a wide
range of sea conditions, from the comparative calm of the South China Sea to the
hostile Northern North Sea. Steel jackets are used in water depths of up to 150m and
may support production facilities a further 50m above mean sea level (MSL). In
deepwater, all the process and support facilities are normally supported on a single
jacket, but in shallow seas it may be cheaper and safer to support drilling, production
and accommodation modules on different jackets. In some areas, single well jackets are
common, connected by subsea pipelines to a central processing platform. Steel jackets
are constructed from welded steel pipe. The jacket is fabricated onshore and then
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floated out horizontally on a barge and set upright on location. Once in position a jacket
is pinned to the seafloor with steel piles. Prefabricated units or modules containing
processing equipment, drilling and other equipment are installed by lift barges on to the
top of the jacket, and the whole assembly is connected and tested by commissioning
teams. Steel jackets can weigh 20,000 tons or more and support a similar weight of
equipment. The figure below shows an example of a steel jacket.
Figure 93: Example of Steel Jacket platform
2. Concrete or steel gravity-based structures can be deployed in similar water depths to
steel jacket platforms. Gravity-based platforms rely on weight to secure them to the
seabed, which eliminates the need for piling in hard seabeds. Concrete gravity based
structures (which are by far the most common) are built with huge ballast tanks
surrounding hollow concrete legs. They can be floated into position without a barge and
are sunk once on site by flooding the ballast tanks. For example, the Mobil Hibernia
Platform (offshore Canada) weighs around 450,000 tons and is designed and
constructed to resist iceberg impact! The legs of the platform can be used as settling
tanks or temporary storage facilities for crude oil where oil is exported via tankers, or to
allow production to continue in the event of a pipeline shutdown. The Brent D platform
in the North Sea weighs more than 200,000 tons and can store over a million barrels of
oil.
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6.3 Development Scenario
Due to Gullfaks B being located between Gullfaks A and C, the produced fluid can be
evacuated to Gullfaks B because of distance and pipeline cost considerations. The distance
from Gullfaks A and C are 4km and 3km respectively and a 12 inch diameter pipe can be used.
That gives an opportunity to host tie-in system expenditure to be reduced, since there is no use
long length pipeline to tie-in to the fluid gathering target at Gullfaks B.
In total, four (4) scenarios were considered for the facility design development for Gulfaks
Field. The scenarios are shown as follow:
Option A – 3 Steel jacket wellhead Platform + Pipeline
Option B – 2 Subsea development platforms + 1Steel jacket wellhead platform +
Pipeline
Option C –1 Subsea development platform + 2 Steel jacket wellhead platforms +
Pipeline
Option D – 3 Steel jacket wellhead Platform + FPSO
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6.3.1 Option A – 3 Steel jacket wellhead Platform + Pipeline
Drilling by Jack up rig
Triple 4 legged steel jacket platform: Minimum facility topsides with NO normal visits;
basic utilities including control, power, corrosion inhibition, oil processing, water
injection, gas compression and storage.
Pipeline from GF-B to terminal onshore – 175 km. Processed crude export via pipeline
to terminal.
Table 44: Option A
Cost Estimates (USD million)
Topside + Substructure (3 Platforms) 165
Pipelines 250
Development Wells 110
Total CAPEX 525
Figure 94: Option A
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12 in. pipe
20 in. pipe
3 KM
4 KM
175 KM
GF-C
GF-B
GF-A
GULLFAKS FIELD
MONGSTAD OIL TERMINAL (BERGEN)
6.3.2 Option B – 2 Subsea development platforms + 1Steel jacket wellhead platform +
Pipeline
Drilling by Jack up rig
One 4-legged steel jacket platform: Minimum facility topsides with NO normal visits;
basic utilities including control, power, corrosion inhibition, oil processing, water
injection, gas compression and storage.
Subsea platforms for GF-A and GF-C
Pipeline from GF-B to terminal onshore – 175 km
Cost Estimates (USD million)
Topside + Substructure (1 Platforms) 55
Pipelines 250
Development Wells 110
Subsea development 180
Total CAPEX 595
Table 45: Option B
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Figure 95: Option B
6.3.3 Option C –1 Subsea development platform + 2 Steel jacket wellhead platforms +
Pipeline
Drilling by Jack up rig
Two 4-legged steel jacket platform: Minimum facility topsides with NO normal visits;
basic utilities including control, power, corrosion inhibition, oil processing, water
injection, gas compression and storage.
Subsea platforms for GF-A
Pipeline from GF-B to terminal onshore – 175 km
Cost Estimates (USD million)
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12 in. pipe20 in. pipe
3 KM
4 KM
175 KM
GF-C
GF-B
GF-A
GULLFAKS FIELD
MONGSTAD OIL TERMINAL (BERGEN)
Topside + Substructure (2 Platform) 110
Pipelines 250
Development Wells 110
Subsea development 90
Total CAPEX 560
Table 46: Option C
Figure 96: Option C
179
12 in. pipe20 in. pipe
3 KM
4 KM
175 KM
GF-C
GF-B
GF-A
GULLFAKS FIELD
MONGSTAD OIL TERMINAL (BERGEN)
6.3.4 Option D – 3 Steel jacket wellhead Platform + FPSO
Drilling by Jack up rig
Triple 4 legged steel jacket platform: Minimum facility topsides with NO normal visits;
basic utilities including control, power, corrosion inhibition, oil processing, water
injection, gas compression and storage.
FPSO is used to transport oil to tanker or oil terminal.
Cost Estimates (USD million)
Topside + Substructure (3 Platforms) 165
FPSO 210
Development Wells 110
Total CAPEX 485
Table 47: Option D
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Figure 97: Option D
Hence, based on CAPEX considerations alone, Option D is chosen due to it having the lowest costs.
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12 in. pipe
20 in. pipe
3 KM
4 KM
175 KM
GF-C
GF-B
GF-A
GULLFAKS FIELD
MONGSTAD OIL TERMINAL (BERGEN)
6.4 Engineering Design and Planning Considerations
The facilities planning for Gullfaks field involved the following considerations:
6.4.1 Platform Design
A Gullfaks platform has integrated a production and utility facility which is typical of offshore
platform configurations. Platform construction is of a modular design which allows all
facilities such as production equipment, piping, cabling and instrumentation to be installed at
an onshore fabrication yard. Considerable cost savings are realized by this approach relative to
offshore installations of these facilities. Gullfaks platform facility was based on a standardized
two-module type design.
6.4.2 Gas Compression Requirements
Three-dimensional reservoir studies indicated that gas injection will be required in the Gullfaks
reservoir for pressure maintenance. The maximum gas production in Gullfaks Field is 27.3
MMscf/d and Central Processing Platform gas compression is 50 MMscf/d. While Gullfaks
maximum gas production is 5.8 MMscf/d which gas compression module in Gullfaks Complex
is sufficient handle and not required to upgrade. The maximum gas injection for gas lift is
3.402 MMscf/d.
6.4.3 Water Injection Requirement
Water injection facilities are planned as the reservoirs were interpreted insufficient aquifer
strength. There’s no water production rate in first year of production in Gullfaks and three
dimensional reservoir studies indicated the water injection starts on the first year. Gullfaks
required 40 Mstb/d. and capacity in Gullfaks field is 120 Mstb/d. There’s insufficient data on
to evaluate water production in Gullfaks Field. Hence, future water injection requirement will
be further evaluated as additional reservoir performance data becomes available.
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6.4.4 Telemetry System
Gullfaks satellite platform is designed for unmanned operation. A microprocessor based
telemetry system operated via a radio link was installed for remote operation of Gullfaks Field.
The following aspects of the Gullfaks operation are remotely handled on Gullfaks Central
Processing Platform:
Individual well testing
Monitoring of well status and production measurements
Monitoring and control of critical equipment
Initiation of a process and emergency shutdown
6.4.5 Corrosion Control - Production Facilities
One of the most significant engineering considerations in the planning of the facilities was the
control of corrosion caused by the high CO2 content of the wellstream. The Gullfaks well
stream contains small amount of carbon dioxide. However, this CO2 content in the well-stream
also requires proper material selection and corrosion protection measures in the facilities
design. Carbon steel has been specified for well tubulars, flowlines and separator vessels for
the Gullfaks process facilities. For the wellheads, it was considered advisable to have stainless
steel lower master valve and alloy steel valve trims for the remainder. Corrosion inhibitor is
injected into the flowlines and the crude oil production pipelines. Corrosion monitoring points
were installed to enable a close scrutiny of susceptible areas in the system.
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6.5 Platform Utilities and Service Facilities
6.5.1 Topside Structure
The topside design mainly depends on the space, facilities required and weight. The platform
will vary in complexity according to the number of wells and type of processing facilities
required. Gullfaks topside structure will be an integrated deck comprises mainly:
Production deck - used to place the well head
Helideck – it welded to the side of the platform for helicopter landing.
Mezzanine deck- it is functioning as to accommodate crane.
Living quarters – Capacity for offshore operation is between 80-120 men.
Figure 98: Typical elevation view of an offshore platform
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Figure 99: Schematic of an offshore platform, illustrating the concept of modularization
Figure 100: Equipment arrangement plan of a typical offshore platform illustrating
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6.5.2 Substructure
Gullfaks jacket shall be a four pile of steel-insert structure and comply with the standard design
regulation. The structure is only few meters in height and it allows some gap between the
seawater level and weather deck. The substructure shall be designed to withstand loading of the
top structure modules, storms and can withstand minor incident such as minor ship crash. The
jacket shall also accommodate the risers for production communication from seabed to
platform, caisson and boat loading with consideration of the sea level depth.
Process Flow
Figure 101: Process Flow Diagram
6.5.3 Wellhead module
Manifold systems
Manifold should have configuration options that include production, injection, and test
manifolds. It as well should have multiple tie-in and header configurations to facilitate
construction of the production system. There are different type of manifolds systems:
1. Production Manifold
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Production manifolds is used to lower the pressure from the wellhead. It consists of a set of
high pressure valves and at least two chokes. These chokes can be fixed or adjustable or a
mix of both. The redundancy is needed so that if one choke has to be taken out of service,
the flow can be directed through another one. By lowering pressure the retrieved gases can
be flared off on site.
2. Injection Manifold
An injection manifold is a structure containing a network of valves and pipework designed
to direct injection fluids to one or more wells. The injection manifolds can be configured
to handle a variety of fluids, typically water or gas, and can be designed to facilitate any
field’s enhanced recovery strategy. The water injection manifold is for feeding injection
water to water injection wells along with metering system while lift gas manifold for
feeding lift gas to well along with injection gas regulation/control and measurement
system.
3. Test Manifold and Test Separator
A plat is receiving a multi phased flow from many wells via manifold. Flow from one well
only may be taken to the test separator. Vessel is used to separate and meter a small amount
of oil and gas. There are several types of test separators can be used which are two-phase
or three-phase or spherical, vertical or horizontal. Different meters will be equipped for test
separators to determine the rates of oil, gas and water. This is important to diagnose well
problems, to evaluate the production performance of individual well and can manage the
reserves properly. Test separators also known as well testers or a well checkers.
6.5.4 Separation
More often, the well produces a combination of gas, oil and water, with various contaminants
that must be separated and processed. The production separators come in many forms and
designs. In gravity separation, the well flow is fed into a horizontal vessel. The retention period
is typically five minutes, allowing gas to bubble out, water to settle at the bottom and oil to be
taken out in the middle. The pressure is often reduced in several stages (high pressure
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separator, low pressure separator, etc.) to allow controlled separation of volatile components. A
sudden pressure reduction might allow flash vaporization leading to instability and safety
hazards.
The separator that will be used for Gullfaks Field is horizontal separators since they are
normally more efficient at handling large volumes of gas than vertical separators. This is
because the interface area is larger in a horizontal separator than a vertical separator, it is easier
for the gas bubbles, which come out of solution as the liquid approaches equilibrium, to reach
the vapor space.
Advantages of horizontal separator:
Horizontal separators smaller and less expensive than vertical for given gas capacity
Liquid droplets easier to separate out of gas continuous phase
Gas bubbles easier to come out of the liquid phase to reach vapour space because interface
area larger
Greater liquid capacity because well suited for liquid-liquid separation
Figure 102: Horizontal Separator
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6.5.5 Metering
Metering stations allow operators to monitor and manage the natural gas and oil exported from
the production installation. These employ specialized meters to measure the natural gas or oil
as it flows through the pipeline, without impeding its movement. This metered volume
represents a transfer of ownership from a producer to a customer (or another division within
the company), and is called custody transfer metering. It forms the basis for invoicing the sold
product and also for production taxes and revenue sharing between partners. Accuracy
requirements are often set by governmental authorities. Typically, a metering installation
consists of a number of meter runs so that one meter will not have to handle the full capacity
range, and associated prover loops so that the meter accuracy can be tested and calibrated at
regular intervals.
6.5.5.1 Crude Oil Metering
At turbine meter station, the flow rate of the crude oil will be metered and regulated by the
surge level control valve located in the crude oil pump discharge header. There will be turbine
meters, piped in in parallel with one meter sparing the other at the meter station. Oil flow
readout will be by a net oil computer.
6.5.5.2 Gas Metering
Gas flowing from the Test Separator and Production Separators will being metered by using
orifice meters. The differentials will be transmitted to a central control panel whose
instruments will provide both instantaneous and totalized flow rates.
6.5.6 Well Control Panel
Pneumatic control panels are designed to monitor crucial wellhead safety parameters. They
provide sequential start up and safe shutdown of production wells.
Surface Facility Protection: A safety analysis or hazardous operability (HAZOP)
analysis of surface facilities including rotary and process equipments is carried out. All
possible hazards, interrelation between various parameters are identified and listed. The
189
functional chart thus evolved is the SAFE (Safety Analysis and Function Evaluation)
chart. The SAFE chart forms the basis for design of panel in surface safety protection.
Fire and gas leakage protection system: Any gas leakage is automatically detected
and appropriate shutdown action initiated to prevent formation of combustible mixture.
All sources of ignition are also shutdown. Any eruption of fire is detected and
appropriate shutdown and suppression action initiated
Well control & Protection: A major function of the wellhead shutdown panel is to
control the well through the surface and sub-surface safety valves. The interrelations
between various valves are well defined and their sequential operation established.
Remote monitoring and control of essential process variables including well testing will
be through the operation station.
6.5.7 Flare system
When raw natural gas are produced in the facilities that are lacking gas transportation
infrastructure, the gas will be transported to flare system to be flared as a waste or unusable
gas. The other consideration to flare the gas is the construction of gas pipelines and utilization
of other gas transportation means is not economically feasible. A gas seal is installed in the
flare stack to prevent the air to flow back into a flare stack due to wind or thermal contraction
of stack gases and create an explosion potential. A liquid seal that is located downstream of the
3-Phase Separator is used to stop flame propagation in the unlikely event of flashback. It is also
used to remove liquid droplets from the gas and also prevent gas from travel to upstream.
Liquid seal contain a predetermined level of water in the base of the drum.
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6.6 Production Support Facilities
6.6.1Water injection
Water Injection will be used as secondary recovery methods for pressure maintenance. It is
relatively low cost and efficient means of improving oil production from a depleting field.
Treated water is injected under pressure into flanks of the oil bearing strata through propose
drilled wells. Water displaces any remaining particles of oil and reduces free space, thus
increase reservoir pressure. To prevent damage to the Reservoir the quality of water injected is
strictly complied with. Also, the health of the pipelines carrying the injection water to the wells
and well platforms is taken care of by dozing chemicals to prevent corrosion. The Major
components of Water Injection systems are; sea water lift pumps, coarse filters, fine filters,
deoxygenation towers, booster pumps, main injection pumps and chemical dosing pumps.
While chemical dozing system is included flocculent, scale inhibitor, corrosion inhibitor,
chlorination, bactericide and oxygen scavenger.
6.6.2 Sea water Lifting and Filtering
Water from sea is Lifted with seawater lift pumps and fed to Coarse Filters and fine filters
for filtering. Coarse filters filter the particle to 20 microns. Fine filters filter the particle to 2
microns. Poly electrolyte and coagulants are added in sea water lift pump discharge to promote
coagulation of suspended particles.
6.6.3 Deoxygenation and Pumping
The filtered water flows to Deoxygenating towers for removal of oxygen. Deoxygenation
prevents formation of aerobic bacterial colonies (sulphur reducing bacteria) in the Water
Injection flow lines. Vacuum pumps and Oxygen scavenger chemical dozed facilitates oxygen
removal in the towers. Booster Pumps take suction from De‐oxygenation Towers and feed
Main Injection Pumps. Scale inhibitors, Bactericide and corrosion inhibitor chemicals are
dozed in the discharge of booster pumps.
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6.6.4 Gas compression facilities
Gas compression facilities are required to provide gas injection for reservoir pressure
maintenance, gas re-injection to dispose of produced gas and gas lift to enhance vertical lift
performance in production wells. The following equipment use for gas compression:
gas compressor complete with driver package
gas scrubber
gas coolers
glycol dehydration system
pipings, control and instrumentation systems
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6.7 Gullfaks Pipeline System
6.7.1 Pipeline sizing
Pipeline sizing play an important role in transporting hydrocarbon from one platform to the
other platform. This is to make sure that the pipeline is capable of transporting fluid at the
required amount and to maintain the fluid velocity in order to avoid solid particle from
depositing at the lower part of the pipeline. The purpose of doing pipeline sizing is to ensure
that the pipeline can accommodate the require capacity within the available pressure
constraints. Pipeline sizing depends on available pressure drop, flowing velocities and the flow
rate of the liquid. The line needs to be large enough in order to accommodate sufficient
pressure to move the fluid in the pipeline. Assuming that available pressure drop can be altered
by changing the outlet pressure which is separator, the pipeline sizing can be selected based on
the fluid velocity and flow rate. There is a limit to the fluid velocity, in order to prevent
pipeline erosion.
It is possible that liquid droplets in the flow stream will impact on the wall of the pipe causing
erosion of the products of corrosion. This is called erosion/corrosion. Erosion of the pipe wall
itself could occur if solid particles, particularly sand, are entrained in the flow stream.
Steps in selecting the pipeline Sizing and wall thickness:
Determine the max and min velocity allowable for specific fluid types
Find pressure drop of the system
Determine the I.D of pipe relative to the velocity
Determine pressure drop in the pipeline
Find the wall thickness based on the standard
Choose the appropriate pipeline size from the standard
Fluid velocity in oil field unit:
V=0.012Q
D2
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Gas velocity in oil field unit:
V=60QgTZ
D2 p
The minimum fluid velocity in multiphase systems must be relatively high to keep the liquid
moving and prevent or minimize slugging. The maximum recommended velocity for gas line is
60 ft/sec to inhibit noise and 50 ft/sec for CO2 corrosion inhibition and maximum
recommended velocity for liquid line is 15 ft/sec. In addition, to re-confirm the earlier
calculation, pipeline sizing also can be decided from
d=[(11.9+ ZTR16.7 P )QL /1000 V ]
1 /2
d = pipe ID, in
Z= compressibility factor, dimensionless
R = gas/liquid ratio, ft3/bbl
P = Pressure, psia
T = gas/liquid flowing temperature, OR
V = maximum allowable velocity, ft/sec
QL= Liquid-flow rate, bbl/d
Standard nominal pipe sizes range from 4-inch (100 mm) up to 80-inch (2000 mm) in
diameter. In petroleum industry, 60-inch is the largest diameter installed to date. Most line-
pipes used on offshore facilities are metallic. Non-metallic pipes are also being used today. A
metallic line-pipe is usually manufactured using one of these techniques:
Seamless Method
Electric Welding (ERW)
Submerged Arc Welding (SAW)
There are two types of Submerged Arc Welding (SAW) pipe. They are Longitudinal
Submerged Arc Welding and Spiral Submerged Arc Welding.
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Pressure Drop Calculation
The rate of flow of mixture is W (lb/hr) = 3180 QgS+ 14.6 Ql(S.G.)R= 106x Qg/Ql
ρm=12409× (S .G ) × P+2.7 × R× S × P
198.7× P+R ×T × Z (lb/ft3)
ΔP drop= 6.9x10-8 xLxW2/(ρm x d5)
Where
d = pipe ID, inZ= compressibility factor, dimensionlessR = gas/liquid ratio, ft3/bblP = Pressure, psiaT = gas/liquid flowing temperature, ORQL= Liquid-flow rate, bbl/dQg = gas flow rate, MMscfd
S = specific gravity of gas at standard conditions (air =1)
(S.G.) = specific gravity of liquid relative to water
Based on data from Well A20 obtained from Nodal Analysis, and reservoir properties, pressure
drop calculation is as following:
Data:
Maximum Pipeline length: 7000ft
Liquid flowrate = 4000 bbl/d
Gas flowrate = 1.9 mmscf/d
(S.G.)= 0.724
S=0.8515
Z=0.774
Temperature =80F
Inlet pressure =900psia
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Results:
W=47426.363 lb/fr
R = 475 ft3/bbl
ρm = 24 lb/ft3
ΔP drop= 45266.36/d5
Line ID (inch) Pressure drop (psia)
2 1414.6
4 44
6 5.8
So, minimum pipeline ID 6 inches is recommended for transporting 2 phase liquid and gas.
6.7.2 Pipeline Classification
The onshore and/or offshore pipelines have several types:
Gathering pipeline
These lines are used to transport oil from field pressure and storage to large tank where it is
accumulated for pumping into the long distance called trunk line. Gathering pipelines typically
consist of lines ranging from 4″-8″ inside diameter.
Trunk pipeline
From large central storage, oil is moved through large diameter, long distance pipeline called
trunk line to refineries. Pump are required at the beginning of the trunk line and pumping
stations must also be spaced along the pipeline to maintain pipeline pressure at the level
required to overcome friction, change in the elevation and other losses.
Transmission or transportation pipeline
Mainly long pipes with large diameters, moving products (oil, gas, refined products) between
cities, countries and even continents. These transportation networks include several compressor
196
stations in gas lines or pump stations for crude and multi-products pipelines. The large
diameter may range from 24 to 60 inches
Distribution pipeline
Composed of several interconnected pipelines with small diameters, used to take the products
to the final consumer. Feeder lines to distribute gas to homes and businesses downstream.
Pipelines at terminals for distributing products to tanks and storage facilities are included in
this group.
6.7.3 Pipeline modeling
Models the entire pipeline system to account for pressure, temperature and flow at major
checkpoints. Based on this model the management system can perform:
Pressure balancing to make certain that pressure set points are correct to meet demand
forecasts and avoid potential overload conditions.
Production allocation, which ensures that producers are able to deliver their contractual
volumes into the network.
Leak detection, which compares actual measured data against dynamic data predicted
by the model. A discrepancy indicates a leak (or a failing measurement). Simple liquid
systems only calculate basic mass balance (in-out), while an advanced modeling system
can give more precise data on size and position of the leak within a certain response
time.
Pig or scraper tracking is used to track the position of the pig within the pipeline, both
from pig detection instruments and the pressure drop caused by the pig in the pipeline.
In case of liquid pipelines transporting batches of different products, a batch transfer
system is needed. Based on information on when each product is injected into the
pipeline, and gravity measurement at the receiving end, it is possible to sequentially
transfer different products, such as gasoline and diesel in the same pipeline. Depending
on product characteristics, there will be an interface section between the two products
that widens as the product moves along the line. This “off spec” product must be
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discarded at the receiving end to avoid product degradation. It is often disposed by
mixing with larger volumes of low grade fuel products. This system is often used with
countrywide refined product distribution to terminals.
6.8 Operation and Maintenance Philosophy
6.8.1 Operation
Gulfaks field will be operated in accordance with relevant operators’ procedures guidelines,
Norwegian Petroleum Directorate (NPD), NORSOK STANDARD, Petroleum Safety Authority
and other applicable statutory requirements. The maintenance philosophy is required to ensure
that the operational integrity in every Gullfaks platform facilities is capable of safety
performing the tasks.
Health, Safety and Environment (HSE) involves health and safety of personnel, preservation of
the environment and company’s reputation, safeguards of structure and facilities production of
hydrocarbon. Preventive Maintenance includes inspection, servicing and adjustment with the
objective of preventing breakdown of equipment. This is appropriate for highly critical
equipment where the cost of failure is high, or where failure implies a significant negative
impact on safety or the environment Breakdown Maintenance is suitable for equipment whose
failure does not threaten production, safety or the environment and where the cost of
preventing failure would be greater than the consequence of failure.
Condition Monitoring is to monitor performance of the equipment on a continuous basis, then
abnormal behavior can be identified, and preventive maintenance can be performed when
required. This obviously takes the equipment out of service, and may be costly. Non
Destructive Testing (NDT) Inspection is to detect flaws or imperfection during manufacture or
those that develop during service. Where internal flaws are suspected, use is made of ultrasonic
testing. It is conceived for the following activities:
Routine inspection and maintenance.
Operational tasks such as replenishing chemicals for wax and corrosion inhibition
injection as well as launching the pig to Gullfaks in the pipeline.
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Housekeeping, consisting of cleaning of sump, solar panels, battery and instrument
checks.
Pipeline Operation Philosophy
The primary process intent is to transport the crude within the pipe line handling capacity of
Gullfaks and its associated network platforms.
Process Control
To achieve the process intent the following shall be monitored and controlled:
Export pressure, temperature and flow rates.
Flow rate fluctuations.
Operations modes: normal/transient-pigging/startup/shut down and blow down.
Moisture/dew point level finally GOR (monitor only).
Pigging
Pipe line requires regular cleaning by pig which removes settled sand, stagnant water collected
at low points (corrosion prevention) ,wax deposit etc. The pig may be in the form of a sphere to
displace fluids or cylinder with brushes to scrape the inside surface of the line. Intelligence
pigs can be used to inspect the pipe line condition and record the results
6.8.2 Maintenance
The aim of maintenance in this case is to protect the technical integrity of the facilities and
pipelines throughout their life cycle, resulting in high availability of equipment and system.
This is in agreement with the design intent to achieve production objectives at optimum costs
without jeopardizing safety, environment, production plans and legal obligations. The
inspection and maintenance philosophy encompasses the following:
i. The designs shall adopt (fit purpose) concept where possible using minimal operator
intervention, reliable components with the highest availability and reliable records.
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ii. Choice of equipment and systems will be based on proven technology and system with
regional spares and technical support.
iii. Utilization of advanced control system with self-diagnostic and predictive maintenance
capability.
iv. Standardization between systems skids and platform.
v. Maintenance Reference Plan (MRP) delineates the lifetime key maintenance activities
to ensure preservation of the facilities technical integrity throughout its lifetime.
vi. Equipment selection and maintenance based on proven technology that satisfies
specific operating condition, specification and maintainability for the lowest life cycle
costs. Consideration to use new technology will be based on significant advantages
offered over current ones.
vii. Maximising predictive maintenance by monitoring key safety and production
equipment and these parameters shall be extended onshore for shore-based specialists’
surveillance.
viii. Corrective maintenance by using complete serviced units shall be made to reduce
equipment downtime and offshore work when changing out faulty units. Bypass
facility, standby or backup of key critical facilities shall be provided where appropriate
to allow for delayed shore-based maintenance or specialists support.
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6.9 Project Schedule
Gullfaks’ proposed project schedule is illustrated in table below. Project delay and cost
overruns are most likely to occur during the fabrication period. Great effort will be put in this
stage to ensure expected output could be delivered on time without the expenses of the quality
and extra cost.
Table 48: Proposed Project Schedule
ActivitiesDuration
(Months)
FDP Approval for Gullfaks and Conceptual Integrated
Development 2
Bid Award Cycle - Conceptual Design 1.5
Conceptual Engineering 4
Bid Award Cycle - FEED 1.5
FEED 4
Bid Award Cycle - EPCC 1.5
Detailed Design 4
Procurement 6
Fabrication 8
Lay Pipeline 1.5
Install Jacket and Topside 2
Hook-Up and Comissioning 1
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6.10 Abandonment
Decommissioning of Gullfaks platform will take place when it is no longer economical to
continue production. During abandonment, all platforms shall be fully removed according to
specification and International Maritime guideline for offshore development structures. Below
are the general abandonment plan is as follows:
Platform should be initially design such that can be removed readily for future
abandonment.
The well shall be cemented and plugged above at least 100 ft from current depleted
zones and killed.
The jacket piles shall be cut below mudline.
All pipeline to and from platform must be pigged, capped and abandoned in-place.
A total of 30-35 days is expected for complete decommissioning of the whole jacket
structure.
Planning for decommissioning is an integral part of the overall management process and
should be considered at the beginning of the development during design. Parts of the facilities
are treated to remove hydrocarbons and other chemicals, wastes or contaminants. Other
components such as flow lines and production components are often left in place or rendered
safe to avoid environmental disturbances associated with removal. The downhole equipment is
removed and the perforated parts of the wellbore are cleaned of mud, scale, and other debris
before wells are plugged and abandoned to prevent fluid migration within the wellbore or to
the surface. Fluids with an appropriate density are placed between the plugs to maintain
adequate pressure. During this process, the plugs are tested to verify their correct placement
and integrity. Finally, the casing is cut off below the surface and capped with a cement plug. It
is prudent to plan for abandonment from the outset, and ensure minimal environmental
disruption.
The following figures show the plugged and abandoned for open-hole completion and for
cased hole respectively.
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Figure 103: Well Abandonment for Open Hole Completion*
Figure 104: General Well Abandonment for Cased Hole
* Retrieved from http://decarboni.se/publications/guideline-risk-management-existing-wells-co2-geological-storage-sites/appendix-d
203
CHAPTER 7 ECONOMIC ENGINEERING
204
CHAPTER 8 HEALTH, SAFETY AND ENVIRONMENT
CHAPTER 9
205
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207
APPENDICES
Production Technology Appendices
Major Risk How each one could add to the
uncertainty of this assessment
Necessary steps that need to be
taken to account for their effects
1. Reservoir Formation
Strength
The formation could damage of
became less integrity during the
production period.
Flow through a gravel packed
completion in a weak sand.
Sand production as the fluid
production increases.
Proper design should be considered
such as the placement of cementing
area to support the borehole
especially.
When conducting the perforation
job, several factors should be
considered in order to have desired
perforated areas. The type of
perforations also need to choose as
optimal as possible, taking the
formation strength into account and
as well as the time and money
factors.
Sand screening tools can be
installed at the bottom hole
assembly of the completion
equipment to avoid higher
production of sand which is
dangerous to some equipments and
as well as inefficient operating
cost.
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2. The Reservoir
Pressure Decline
Pattern
As the production started, the
reservoir pressure will start to
decline.
It will sometime change the
reservoir type, from a initially oil-
water reservoir to gas-oil-water
reservoir, due to solution gas
liberated into the reservoir,
forming a gas cap portion.
Proper installation of completion
equipments at it optimal and best
selection.
Available reservoir data should be
reconsidered and taken into
account while designing the
completion equipments. The gas
liberated and forming a gas cap
portion will make the oil shrink
and thus reducing the production of
oil.
3. Volume of oil
initially in place
The initial volume of oil in place
is usually estimated at the early
stage of production in order to
estimate the possible hydrocarbon
that could be recovered.
The volume will affect the
economical factor of the field
development.
Maximize the use of available data
such as from the exploration and
logging activities.
The most appropriate correlation
should be applied in order to get
higher recovery factor to the
nearest true value produced.
4. Shallow gas Blowout / gas kick Drill pilot hole
5. Clay swelling Reduces wellbore diameter Use SBM / OBM
6. Wax deposition Decreases production rate Inject hot oil through tubing
7. High CO2 content Facilities corrosion Add corrosion inhibitor
CO2 removal at CPP
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8. Emulsion Ineffective oil-water separation
process
Add demulsifier
9. Sand production Reduces production and causes
facilities problems
Sand control e.g. gravel pack,
stratapac
10. Scale formation Decreases porosity Add scale inhibitor
11. Reservoir Continuity Reserve Estimation Detailed study on G&G Data
210
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