Yme New De ve lop me nt
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Document Title:
Basis of Design
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Doc. Title:
Basis of Design
Document No.:
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CONTENT 1
Introduction ................. ................. ................. ................ ................. ................ ................ 7 1.1
Purpose .................................................................................................................................................. 7
1.2
Yme Field and License Information ........................................................................................................ 7
1.3
Project Background ................................................................................................................................ 7
1.4
Definitions and Abbreviations ................................................................................................................. 9
1.5
References ........................................................................................................................................... 11
1.3.1 1.4.1
Project Description .................................................................................................................. 8 Units ..................................................................................................................................... 11
2
Regulatory Compliance......... ......... .......... ......... .......... ......... ......... .......... ......... .......... .. 12
3
HSE .............. ................. ................. ................. ................ ................. ................ .............. 13 3.1
4
HSE Goals............................................................................................................................................ 13
Field Description .............. ................. ................. ................. ................ .................. ....... 14 4.1
Reservoir Description and Subsurface Evaluation ............................................................................... 14
4.2
Drainage Strategy ................................................................................................................................ 15 4.2.1
Injection Strategy .................................................................................................................. 16
4.2.2
Evaluation of lift mechanism ................................................................................................. 16
4.2.3
Evaluation of Oil Capacity and Liquid Handling Capacity ..................................................... 17
4.2.4
Gas disposal Strategy ........................................................................................................... 17
4.2.5
Beta North............................................................................................................................. 17
4.2.6
Infill drilling on Gamma ......................................................................................................... 17
4.2.7
Gamma North East ............................................................................................................... 17
4.3
Reservoir Development Plan ................................................................................................................ 18
4.4
Production Capacities .......................................................................................................................... 21
4.3.1
4.4.1
5
6
Number and type of wells ..................................................................................................... 18
Gas handling capacity .......................................................................................................... 21
Fluid Profiles ................ ................. ................. ................ ................. ................ .............. 22 5.1
Production Schedule ............................................................................................................................ 22
5.2
Production Profiles ............................................................................................................................... 22
5.3
Pressure Profiles .................................................................................................................................. 29 5.3.1
Production W ells ................................................................................................................... 29
5.3.2
Injection Wells ....................................................................................................................... 29
5.4
Temperature Profiles ............................................................................................................................ 32
5.5
Closed in Tubing Head Pressures ........................................................................................................ 33
Production Chemistry .................................................................................................. 35 6.1
Pressure, Volume and Temperature Data ............................................................................................ 35
6.2
Crude Oil Analysis ................................................................................................................................ 35
6.3
Dead Crude Assay and Viscosity Data ................................................................................................. 38
6.4
Formation and Sea Water Data ............................................................................................................ 40
6.5
Hydrogen Sulphide and Carbon Dioxide .............................................................................................. 40
6.2.1
Miscellaneous fluid properties ............................................................................................... 38
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6.6
6.6.1
Wax Appearance Temperature ............................................................................................. 41
6.6.2
Pour Point ............................................................................................................................. 41
6.7
Asphaltenes.......................................................................................................................................... 41
6.8
Scale .................................................................................................................................................... 42
6.9
Hydrate Formation................................................................................................................................ 42
6.10
7
Wax ...................................................................................................................................................... 41
6.9.1
Hydrate Formation on Gamma and Beta .............................................................................. 42
6.9.2
Main Hydrate Conclusions .................................................................................................... 42
6.9.3
Hydrate Strategy ................................................................................................................... 43
6.9.4
Hydrate Curve ....................................................................................................................... 43
Separation Issues................................................................................................................................. 43 6.10.1
Salinity .................................................................................................................................. 44
6.10.2
Emulsions and Foams .......................................................................................................... 44
6.11
Corrosion and Materials ....................................................................................................................... 44
6.12
Chemical Injection Requirements ......................................................................................................... 45
Drilling and Wells ................ ................. ................. ................. ................ ................. ..... 47 7.1
Well Design Principles .......................................................................................................................... 47
7.2
Yme Gamma ........................................................................................................................................ 47 7.2.1
Yme Gamma W ellbore trajectories ....................................................................................... 48
7.2.2
Well summary ....................................................................................................................... 49
7.3
Yme Beta.............................................................................................................................................. 49
7.4
7.3.1 Well summary ....................................................................................................................... 51 Artificial Lift ........................................................................................................................................... 51 7.4.1
Basis of design ..................................................................................................................... 51
7.4.2
Detailed - Downhole ESP System as Installed ..................................................................... 53
7.4.3
Future ESP’s Gamma ................................................................................................ ........... 54
7.4.4
Subsea and Surface Equipment Requirements .................................................................... 54
7.5
ESP Topside Interfaces: ....................................................................................................................... 55
7.6
Well Clean-up ....................................................................................................................................... 55
7.7
Surface Intervention ............................................................................................................................. 55
7.8
Subsea Intervention ............................................................................................................................. 56
7.7.1
7.9
8
Workover requirements......................................................................................................... 56
7.8.1
Base Case ............................................................................................................................ 56
7.8.2
Reasoning for Base Case ..................................................................................................... 56
Drilling and Wells References .............................................................................................................. 56
Production Technology......... ......... .......... ......... .......... ......... ......... .......... ......... .......... .. 58 8.1
Introduction........................................................................................................................................... 58
8.2
Historic Context .................................................................................................................................... 58
8.3
Sandface Completion and Inflow .......................................................................................................... 59
8.4
Measurement, Monitoring and Sampling .............................................................................................. 62
8.3.1
Basis of Design ..................................................................................................................... 59
8.4.1
Summary .............................................................................................................................. 62
8.4.2
Well sampling ....................................................................................................................... 64
8.4.3
Sand monitoring .................................................................................................................... 64
8.4.4
Well testing and allocation .................................................................................................... 64 Page 3 of 119
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8.4.5
Integrity and barrier testing. .................................................................................................. 65
8.4.6
Downhole monitoring and well intervention........................................................................... 65
Subsea............ ................. ................. ................ ................. ................ ................. ........... 66 9.1
Subsea Facilities and Document References ....................................................................................... 66
9.2
Subsea Design Codes, Standards and Guidelines ............................................................................... 67
9.3
Design Life ........................................................................................................................................... 68
9.4
Location ................................................................................................................................................ 68
9.5 9.6
Subsea Infrastructure Overview ........................................................................................................... 69 Material Selection ................................................................................................................................. 70
9.7
Subsea System Description ................................................................................................................. 70 9.7.1
General Information .............................................................................................................. 70
9.7.2
Design Well Flowrates .......................................................................................................... 70
9.7.3
Well Shut-in Pressures and Maximum Wellhead Flowing Temperature ............................... 70
9.7.4
Drilling Interfaces and Workover Facilities ............................................................................ 71
9.8
Subsea Xmas Tree and Workover System .......................................................................................... 71
9.9
Subsea Structures ................................................................................................................................ 72
9.8.1
9.10
Tree Design Overview .......................................................................................................... 71
9.9.1
Subsea Template Beta ......................................................................................................... 72
9.9.2
Subsea Template Beta North................................................................................................ 72
9.9.3
Subsea Production Manifold ................................................................................................. 72
Flowlines, Risers, Flowline Jumpers and Umbilicals ............................................................................ 72 9.10.1 9.10.2
General ................................................................................................................................. 72 Beta North Flowlines ............................................................................................................. 73
9.10.3
Flow Assurance .................................................................................................................... 73
9.10.4
Erosion.................................................................................................................................. 73
9.10.5
Power System ....................................................................................................................... 73
9.11
Risers
74
9.12
Subsea Production Control and Monitoring System ............................................................................. 74
9.13
Subsea Metering .................................................................................................................................. 74
9.14
Leak Detection from Subsea Facilities ................................................................................................. 74
9.15
Sand Detection from Subsea Facilities ................................................................................................. 75
9.16
Preservation Status of Existing Facilities .............................................................................................. 75
9.12.1
Production Monitoring ........................................................................................................... 74
10 Production Facilities .................................................................................................... 76 10.1
Description of Facilities ........................................................................................................................ 76
10.2 10.3
Storage 76 Submerged Loading System ................................................................................................................ 79
10.4
10.3.1
Requirements for existing offloading ..................................................................................... 79
10.3.2
Alternative offloading ............................................................................................................ 79
Topsides and W ellhead Module ........................................................................................................... 79 10.4.1
General ................................................................................................................................. 80
10.4.2
Well Conductor and Riser Caisson ....................................................................................... 81
10.4.3
Platform Wells ....................................................................................................................... 82
10.4.4
Production Separation .......................................................................................................... 82
10.4.5
Gas Compression and Treatment ......................................................................................... 84 Page 4 of 119
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10.4.6
Produced Water Treatment................................................................................................... 85
10.4.7
Water Injection ...................................................................................................................... 85
10.4.8
Power Requirements and Fuel Supply ................................................................................. 86
10.4.9
Chemical Injection ................................................................................................................ 86
10.4.10
Measurement ........................................................................................................................ 87
10.4.11
Sampling Facilities ................................................................................................................ 88
10.4.12
Subsea Storage Tank and Caisson Interfaces...................................................................... 88
10.4.13
HVAC Design Temperatures ................................................................................................ 88
10.4.14
Allowance for Future tie-ins and options ............................................................................... 88
10.5
Design Life ........................................................................................................................................... 89
10.6
Environmental Targets ......................................................................................................................... 89
10.7
Operational Availability ......................................................................................................................... 89
11 Metocean Data ................ ................. ................ ................. ................. ................. .......... 91 11.1
Temperature data ................................................................................................................................. 91 11.1.1
Air Temperature (°C) ............................................................................................................ 91
11.1.2
Seawater Temperature ......................................................................................................... 91
12 Summary of Geotechnical Conditions ........................................................................ 93 12.1
Bathymetric data .................................................................................................................................. 93
12.2
Yme Beta development site.................................................................................................................. 93
12.3
Flowline/ umbilical route ....................................................................................................................... 93
12.4
Production facility site........................................................................................................................... 94
12.5
Subsidence........................................................................................................................................... 94
13 Yme Storage Tank and Caisson ......... ......... .......... ......... .......... ......... ......... .......... ....... 95 13.1
Existing caisson structure ..................................................................................................................... 95 13.1.1
Caisson support system and document references .............................................................. 95
13.1.2
Caisson Structure verification ............................................................................................... 95
13.1.3
Caisson Support Requirements ............................................................................................ 96
13.1.4
Cathodic protection system................................................................................................... 96
13.1.5
Structural Foundation for new Wellhead Module .................................................................. 96
14 Definitions .............. ................. ................. ................. ................ ................. ................ ... 97 14.1
14.2
14.3
Lifetime 97 14.1.1
Design Life ............................................................................................................................ 97
14.1.2
Integrity Life .......................................................................................................................... 97
14.1.3
Service Life ........................................................................................................................... 97
Production Availability .......................................................................................................................... 97 14.2.1 Availability ............................................................................................................................. 98 14.2.2
Wells Availability ................................................................................................................... 98
14.2.3
Production Availability ........................................................................................................... 98
14.2.4
Export Availability ................................................................................................................. 99
14.2.5
Turnaround (Shutdown) Availability ...................................................................................... 99
Vapour Pressures (RVP/ TVP) ............................................................................................................. 99 14.3.1
Reid Vapour Pressure (RVP) ................................................................................................ 99
14.3.2
True Vapour Pressure (TVP) ................................................................................................ 99
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14.4
HSE Plan 99
14.5
Zero environmentally harmful discharge concept ............................................................................... 100
14.6
14.5.1
Use of Chemicals ................................................................................................................ 100
14.5.2
Produced water................................................................................................................... 100
Stream Day vs. Calendar Day rates ................................................................................................... 101 14.6.1
Stream Day ......................................................................................................................... 101
14.6.2
Calendar Day ...................................................................................................................... 101
15 References ................ ................. ................. ................. ................ ................. .............. 102 Appendix 1 – Production Profiles ................................................................................... 104
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1
Introduction
1.1
Purpose The objective of this Basis of Design is to provide a basis to be used for design/ adaptation of a new topsides facility for the Yme New Development Project. This Basis of Design will also control the design development throughout each project phase and Reference between project phases. Together Regulatory Plan (ref Error! source not found. ), the with BoDawill form the Compliance technical basis for the project. All work to be performed in the Yme New Development project shall comply with the latest revision of Basis of Design (BOD); deviations from the BOD shall be subject to Management of Change (MOC).
1.2
Yme Field and License Information The Yme Field is located approximately 100 km from the Norwegian coastline, in the Egersund basin in the central part of the North Sea. The water depth is 93m. The field consists of two main structures: Yme Beta and Yme Gamma, which are located approximately 12 km apart. The Gamma structure was discovered in 1987 and in 1990 oil was proven in the Beta structure. Current License owners are: • Repsol Norge AS (operator): 60 % •• •
Lotos Exploration and Norge AS: 20 % Kufpec Norway AS: 10Production % OKEA AS: 10%
Figure 1-1 North Sea Area Map
1.3
Project Background Statoil developed the field using Mærsk Giant Jack-Up Drilling rig with processing facilities and a separate storage vessel for production in the period 1996-2001, achieving a cumulative production of 51 mmstb. The field was abandoned in Page 7 of 119
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2001 following low oil prices and significant requirements for investments in the field. Paladin Resources was awarded the license as operator from Norwegian Authorities in 2004 and initiated work for a new Plan for Development and Operation (PDO) for the Yme field. Paladin was acquired by Talisman in 2005 which was granted permission to re-develop the field in 2007 based on an estimated 66 mmstb remaining reserves. The basis for the re-development was the use of a Mobile Offshore Production Unit with Storage (MOPUstor) at the Gamma location, and tie-back of subsea templates at the Beta location. All wells were drilled and subsea equipment, including subsea storage tank and caisson, were installed on the field prior to arrival of the MOPU. Due to safety reasons the MOPU was evacuated in 2012 and finally removed in 2016. In 2015 the Joint Venture decided to abandon the PDO and initiate work to abandon the field. Changing market conditions in 2016 provided a potential for lease of existing Jack-Up rig, FPSO and general reduction in rates and costs which represents a new opportunity for the Yme field.
1.3.1
Project Description The Yme New Development Concept is based on lease of either a production facility or a combined production and drilling facility installed on the Gamma location. A new wellhead module willbe made to be installed ontop of the existing caisson. The project will consider either a redeployment, intercept or new build. The existing wells, caisson, pipelines, subsea templates shall be reused and the existing storage tank and subsea offloading system can be reused based on proposal. Some repair work is required on existing facilities, most notably a Caisson Permanent Support and SLS. A new subsea development on the Beta North structure will be tied in to the existing subsea infrastructure. At present, five (5) new wells is planned to be drilled, including one (1) producer and one (1) water injector at Beta North and two (2) producers and one (1) water injector at Gamma. The layout of the Yme New Development Facilities is shown inFigure 1-2.
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Figure 1-2 Example of Yme New Development Layout
1.4
Definitions and Abbreviations Terms that require special definition are specified in section14 of this document. Abbreviations are given below:
AoC API ASV bbl Bg BoD bpd BS&W CCR CITHP CPS CTESP DHSV DLS DnV DNVGL EMS EOS ESD
Acknowledgement of Compliance American Petroleum Institute (Standard) Annular Safety Valve barrels gas formation volume factor Basis of Design barrels per day Base Sediment and Water Central Control Room Closed In Tubing Head Pressure Caisson Permanent Support Coiled Tubing Electric Submersible Pump DownHole Safety Valve DogLeg Severity Det norske Veritas Det norske Veritas (Germanische Lloyd) Enhanced Monitoring System Equations of State Emergency Shut Down
ESP FEED GOR HP HPU HSE ICSS ID ISO Klif KPI
Electric Submersible Pump Front End Engineering and Design Gas Oil Ratio High Pressure/ Horse Power Hydrauliv Power Unit Health Safety Environment Integrated Control and Safety System Internal Diameter International Standards Organisation Climate and Pollution Agency Key Performance Indicator Page 9 of 119
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LAT LP MDBRT MODPU mmstb MSL MW MWD M-SAS
Lower Astronomical Tide Low Pressure Measured Depth Below Rotary Table Mobile Offshore Drilling and Production Unit Million stock tank barrels Mean Sea Level Mega Watt Measurement While Drilling Master Surface Annulus Safety Valve
NCS NDT NEA NORM NOROG NORSOK NOx NPD OBM OIW P50 Pb PDO PGB PLEM PLT POB
Norwegian Continental Shelf Non Destructive Testing Norwegian Environment Agency (former Klif) Normally Occuring Radioactive Materials Norwegian Oil and Gas Association Norsk Sokkels Konkurranseposisjon (Standard) Nitrogen Oxides Norwegian Petroleum Directorate Oil Based Mud Oil In Water 50% probability of exceedence bubblepoint pressure Plan for Development and Operation Permanent GuideBase PipeLine End Manifold Production Logging Tool Personnel on Board
ppm parts per million PSD Process ShutDown PSDM PreStack Depth Migration PVT Pressure Volume Temperature PW Produced Water RNAS Repsol Norge AS ROV Remotely Operated Vehicle RVP Reid Vapour Pressure SAS Safety and Automation System SLS Submerged Loading System Sm3 Standard cubic meter SRB Sulphate Reducing Bacteria STOIIP Stock Tank Oil Initially In Place SW Sea Water THP Tubing Head Pressure TVD True (or Total) Vertical Depth TVDSS True Vertical Depth SubSea (below seabed) TVP UTM VOC VSD WAG WAT WC WHM WI XMT
True Vapour Pressure Universal Transverse Mercator coordinate system Volatile Organic Compounds Variable Speed Drive Water alternating Gas Wax Appearance Temperature WaterCut Well Head Module Water Injection x-mas tree
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1.4.1
Units The project shall use metric units except for pipe diameters which shall be in inches. Alternative units can be included in parenthesis where this is considered to add clarity. Standard conditions are defined as 15°C and 1.01325 bara, normal conditions as 0°C and 1.01325 bara, and stock tank conditions as 15°C and 1.01325 bara. Further to NPD regulations: Standard reference conditions for pressure and temperature shall when metering oil and gas be 101,325 kPa and 15 °C.
1.5
References References for this document are given in section 15.
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2
Regulatory Compliance Figure 2-1 show the hierarchical relations between acts, regulations, guidelines, standards and procedures according to Norwegian regulatory framework. Compliance with this regulatory framework must be demonstrated by the operator (anyone executing on behalf of the licensee the day to day management of the petroleum activities) on the Norwegian Continental Shelf.
Figure 2-1 Norwegian Regulatory Framework Yme New Development compliance to these regulations is set forth in the Regulatory Compliance Plan for the project.
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HSE The Yme New Development will comply with the requirements of Repsol’s Health, Safety and Environment Policy and Management System standards for health, safety and environmental performance. It comprises the following key principles: In case of conflict between safety and operational results, all employees and contractors have the responsibility to choose safety, and the Directorate will support that choice. Repsol will systematically establish goals and objectives for continuous improvement in health, safety and environmental protection. The company's goal is to carry out all activities without injuries or other negative effects on people's health, and without any damage to the external environment. Repsol will maintain regular communication with stakeholders and will work with local communities and the society sharing its knowledge and reporting in a trustworthy and transparent manner.
3.1
HSE Goals The following outline goals for HSE performance shall be used for the project: Zero harm to people and environment Zero accidents or losses Zero work related accidents or illnesses
Zero accidental spills or emissions
The following KPI’s are valid for the project: TRIF = < 2.75 LTIF = < 1.37 Spills Frequency = 0 HPI = 0 DO frequency = 1.6 PSE tier 1 = 0 PSE tier 2 = 0 The contractors need, as a minimum, be aligned with project KPIs above. As the project develops more specific HSE targets shall be detailed within the HSE Plan (see section 14.4).
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4
Field Description
4.1
Reservoir Description and Subsurface Evaluation The Yme field is made of two separate hydrocarbon accumulation clusters, Beta and Gamma, which are split into smaller segments. The reserves in the Yme field are located in the middle Jurassic Sandnes formation which is a shallow marine shore face deposit. The top reservoir depth is 3100-3200 m TVDSS. Pressure measurements in the 2009 – 2010 development wells drilled by Talisman indicated pressures of around 340 bars and 327 bars in Beta East and Gamma structures respectively, compared to a pre-production virgin pressure of 360 bars at the same depth. The oil is 37° API oil with a GOR ranging from 61.3 Sm³/Sm³for Gamma to 54.4 Sm³/Sm³ for Beta. The permeability of the reservoir is ranging from 1-1000 mD and the core porosity from 12-24%. The reservoir technical data base for the Yme reservoirs is extensive compared to the size of the field, as a result of earlier production by Statoil. The well data base contains of 38 wells: 9 exploration / appraisal wells 1987 – 1999 17 development wellbores 1996 – 2000 1 exploration well 2005 11 development wellbores 2009 – 2010 There is also 5 years of production history from 1996 – 2001. Extensive work has been performed since 2010 in order to update all geophysical, geological, petro
physical andfrom reservoir technical modelsinon Yme, incorporating all the seismic new information the drilling campaign 2009/2010 and reprocessed on Yme Beta (PSDM). The reservoir technical models where history-matched to 5 years of production and to the pressures observed in 2009 - 2010. New predictions, optimization of drainage strategy and drilling campaigns where performed.
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Figure 4-1 Yme Segments and location of the wells drilled by Statoil (1995 2001) and Talisman (2009-2010)
Segment
Produced (mmstb)
P50 STOOIP 2016 (mmstb)
Beta North
2.4
58
Beta East
13.4
90
Beta West
0.2
13
Gamma West + Gamma South East
35
156
Gamma North East
2.40
23
Total 51 340 Table 4-1: In place volumes per segment. Gamma West and South East are grouped together as they are the segments in Gamma with the longest production history (and therefore the smallest uncertainty range)
4.2
Drainage Strategy The main drainage strategy for the Yme reservoir is produced water reinjection in order to support reservoir pressure. The produced gas will be injected in WAG cycles in Gamma West. Water injection is needed in order to optimize recovery and production rates from the field. Natural aquifers are present and will contribute to maintaining the reservoir pressure in most areas, but produced water reinjection will be required to optimize reservoir recovery.
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The existing production wells are open-hole completed with long horizontal sections located in the high permeable layers in the reservoir; hence there will be limited or no possibilities to shut-off water production from individual zones. Therefore, a significant amount of produced water will have to be handled during the life of field. If more wells are drilled into the reservoirs on a later stage, sliding sleeves will be evaluated to enable control of inflow from the individual branches, and to reduce the water production, but this has not been included in the development plan at this stage. High power electrical submerged pumps (ESP’s) are installed in both the Gamma and Beta wells. Gas lift was included as a contingency back-up lift mechanism for the subsea Beta production wells, for use in the event of dual ESP failure. When the new Beta East wells were drilled in 2009, the reservoir pressure was 80 bars higher than expected, proving a significantly higher aquifer support. Gas lift is now the preferred artificial lift mechanism on Beta. This solution reduces uncertainty and cost related to the ESP changes on subsea wells, and due to the higher than anticipated pressure support in Beta, it results in a minimal reserves reduction. For Platform wells (Gamma East location), existing ESP’s will be attempted started, with immediate change out if start fails. The field GOR is low, some of the produced gas will be used as fuel for power generation and the excess associated gas will be injected in WAG cycles in Gamma West. WAG in Gamma West is expected to lead to gas breakthrough, omitting the need for ESP’s in these wells. The resultingincrease in GOR from these wells is expected to remove need for artificial lift for start-up in later field life. Gas lift will be installed to enable optimisation of production.
4.2.1
Injection Strategy The current Yme development is based on long horizontal producers and pressure support from down-flank water and gas injectors. An evaluation with regards to drainage strategy and the degree of voidage that is required to optimize production in each segment has been done. The evaluation concluded that produced water reinjection appeared to be the best alternative. See reference 49.
4.2.2
Evaluation of lift mechanism The lift mechanisms were re-evaluated autumn 2016 (see reference 49). All producers on Yme Gamma and Yme Beta are currently recompleted with a dual set of ESP pumps. In addition, the Yme Beta subsea wells are completed with gas lift as a backup system that can be used if and when the ESPs fail. Gas lift is now the preferred artificial lift mechanism on Beta. Gas injection in Gamma West results quickly in gas to liquid ratio above 200 Sm3/Sm3 in Gamma West producers. As a result, it’s not recommended to rely on ESPs in Gamma West producers. In Gamma East, ESPs give a better artificial lift and adds some reserves to Yme Gamma. However, this benefit is counteracted by the additional cost of workovers required by ESP replacements. The current recommendation is to have gas lift in Gamma East, and to provide two VSDs to suit the 900 and 1200 hp ESP systems.
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4.2.3
Evaluation of Oil Capacity and Liquid Handling Capacity The subsurface optimisation study (reference 49) show required liquid handling capacities. At this rate, the oil plateau is less than one year, which indicates the optimum oil capacity need not be set in stone. The final choice of capacities for the Yme field can be found in Table 4-3
4.2.4
Gas disposal Strategy There is no gas export possibility on Yme. The gas production is limited, but is expected to exceed the need for fuel gas. A Gas disposal solution is therefore a necessity, allowing for full gas injection in the event of Fuel gas system being unavailable. When Statoil was operating Yme between 1996 and 2001, the excess gas was injected in the A-5 well in the Gamma West structure between July 1996 and July 1998, then A-5 was used to dispose produced water, and the gas was injected in the dry Epsilon prospect. Reference 49 describes the gas disposal strategy in Yme. The plan for Yme is to re-inject the excess produced gas in the C-5 and C-6 injectors in Gamma West in water alternating gas (WAG) cycles. The cycle frequency is approximately 6 months.
4.2.5
Beta North The most likely concept for Yme Beta North development is a template solution placed in the vicinity of the Beta manifold and connected to the existing subsea systems. During the last months the geological and reservoir technical models for Yme Beta North have been updated. The reservoir model has been history matched and an uncertainty evaluation of recoverable reserves has been done.
4.2.6
Infill drilling on Gamma The current wells in Gamma and the wells that will be drilled from the three remaining slots allow for an effective drainage of the high permeability zones in Gamma. However, the drainage of lower permeability zones can only be achieved by dedicating wells to these lower permeability zones. This may be done by side-tracking existing wells. Alternatively, these reserves could be accelerated by adding a new subsea template connected to Gamma
4.2.7
Gamma North East When C-7 was drilled in 2010, the well hit the reservoir deeper than expected and the development of the Gamma North East structure was considered uneconomical assuming the same oil/water contact depth as in Gamma North West. The Gamma North East contact was revisited in the petro physical study, showing that the log data and saturation-height functions are consistent with a free water level at ~3243 m tvdss. The model starts to match the log interpreted water saturation with a free water level at 3240.5 m tvdss. Because of the uncertainty of this approach, a slightly more conservative FWL at 3239 m tvdss was introduced in the Gamma North East structure, resulting in oil in place volumes of 23 mmstb in the Gamma North East structure. The considered development scenario for the Gamma North East structure is a dual branch producer, with one branch on each side of the small fault modelled in Gamma North East.
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4.3
Reservoir Development Plan
4.3.1
Number and type of wells The current Yme development is based on long horizontal producers and pressure support from down-flank water injectors. The following producers and injectors are drilled, completed and ready to be started as soon as a new production facility is ready: o Yme Gamma: four oil producers and two water injectors o Yme Beta: two oil producers and one water injector (drilled from a subsea template) Segment
Well Name
Type of well
Gamma North West
9/2-C-2 AT2
Oil Producer
Gamma North West
9/2-C-3 T3
Oil Producer
Gamma South West
9/2-C-4 T2/ T3
Dual lateral Oil Producer
Gamma West
9/2-C-5
WAG injector
Gamma West
9/2-C-6
WAG injector
Gamma South East
9/2-C-1
Oil Producer
Beta East
9/2-D-1 H
Oil Producer
Beta East
9/2-D-2 H
Oil Producer
Beta East
9/2-D-3 H
Water Injector
Table 4-2 Name and type of wells drilled in 2008 - 2010 campaign All producers on Yme Gamma and Yme Beta are currently recompleted with a dual set of ESP pumps. In addition, the Yme Beta subsea wells are also completed with gas lift as a backup system that can be used if and when the ESPs fail. On Beta, the current strategy is to use gas lift as the artificial lift method during field life as it reduces the cost and uncertainty related to the frequent ESP changes that are not desired on subsea wells.
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In addition to these wells 5 new wells are planned to be drilled into the Yme reservoirs as part of the base plan. The new wells are: One new water injector into the Yme Gamma East flank Two new oil producers on Yme Gamma: one on the South West flank and one on the North East flank One oil producer and one water injector drilled into the Yme Beta North reservoir which is planned to be developed with a new template connected to the existing subsea system at Yme Beta. The production profiles include the production from all segments on Yme Gamma
and Beta including the Beta North Area.
Gamma North
C-2 A C-6
C-3
Gamma South East
C-4
C-1
Gamma South West
C-5
Figure 4-2 Location of the Yme Gamma wells
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Figure 4-3 Location of the Yme Beta wells
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4.4
Production Capacities The following production and injection maximum capacities are set for the new facilities: Service
Units
Facility Design Rates
3
m /d
6 500 - 9 000Note 4
Produced Water Treatment
3
m /d
12 500Note 5
Gross Produced Liquids
m3/d
17 800Note 5
Produced Oil
HP Gas Compression, Dahydration and Injection
Sm3/d
Gas Lift
Sm3/d
700 000Note 2
Seawater De-aeration
m3/d
6500Note 3
Produced Water Injection
m3/d
13 000Note 5
Barg
10
Inlet Separator Pressure Note
900 000 – 1 100 000Note 1
3
1. 900 000 Sm /d require two ESP’s in operation. As far as possible the plant shall be designed to achieve 1 100 000 Sm3/d (Full Gas Lift). 2. Only applicable for sizing of gas lift pipework etc. 3. Design to allow for future offshore installation of SW treatment and injection facilities. 4. Given short expected plateau production, the maximum oil capacity can be adjusted with limited economic impact. 5. Somewhat lower rates may be acceptable as long as this does not significantly impact oil production (see profiles in chapter 5.2).
Table 4-3 Production Capacities The reservoir is to produce against an inlet pressure (@ Gamma wing valves and Beta riser valve) of 13 barg. The first stage separator will operate around 10 barg. The capacities listed in the table above are subsurface restrictions based on stream day rates. Individual equipment design rates will differ to achieve the above rates.
4.4.1
Gas handling capacity The range indicated in gas handling capacity reflects the change in artificial lift strategy. The srcinal plan (initial Yme Re-Development in 2006) was that the Beta wells would produce with ESP’s for three years before failure and then gas lift would come in operation for one year. With Gas Lift now being the prepared option also for Gamma West – and with the expectation of Gas Breakthrough following gas injection – the required gas capacity is significantly increased. Only the two wells in Gamma East will have ESP’sconnected, and even for these wells, Gas Lift will be an option when pumps fail. Page 21 of 119
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5
Fluid Profiles Production profiles are obtained from two reservoir models, one from Gamma and one from Beta. They are constrained in each model so that combined flow is in line with total facility capacities: 1/3 for Beta and 2/3 for Gamma.
5.1
Production Schedule Production start is scheduled for September 2019 with six wells pre-drilled on Gamma (4 x oil producers and 2 x WAG injectors) and three subsea wells from Yme Beta (2 x oil producers and 1 x W ater injector). Soon after production start, 3 new wells will be drilled from the remaining Gamma slots. Beta North will be developed in 2020, most likely with a new template and a producer / injector pair. The existing Gamma wells have also been identified as suitable for sidetracks at a later date when watercut increases, and infill targets will be matured further. Sidetracks are not included in the base case profiles.
5.2
Production Profiles The pre-drilled wells will be phased to allow an initial oil production level of 54.000 stb/d (approx 54 000 Sm3/d). If oil rates are restricted further by existing facilities, the phasing of wells will be changed. The oil production rate will decline, as water cut develops. The base reserves for this re-development scenario are approximately 50 million bbls. Production profiles (oil, gas, produced and injected water) are included in the following graphs, with individual well production rates also tabulated (Appendix 1). Yme PVT data have been reviewed and three compositions will be used, distinguishing between the Yme Gamma, Beta East and the Beta North reservoir respectively (reference 12, 13). The facilities system design, with the use of the 4” service line for Gas Lift, permits the use of gas lift in Beta wells. Although gas lift was not the preferred lift mechanism in the first Yme redevelopment and considered as a back-up solution only, it is now chosen as the field life-time artificial lift solution for the Beta wells in order to avoid costly work-overs on subsea wells. An allowance is to be made in the topsides design to supply to approximately 700,000 Sm³/d of lift gas to Beta and Gamma production wells. The following graphs and production tables (Appendix 1) identify: Production profiles for oil, produced water, gross liquids, and gas (all data is presented as stream day rates without any system availability impacts), Graph displaying water production and injection.
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Yme Oil Production (sm3/d) - Stream Days 10 000 9 000 8 000 7 000 Gamma Oil 6 000
Beta Oil Total Oil
5 000
HP Capacity 4 000
Test Capacity
3 000
Total Capacity
2 000 1 000 01.sep.19
02.mar.22
31.aug.24
02.mar.27
01.sep.29
02.mar.32
01.sep.34
Figure 5-1 Yme Field Oil Production and capacity restrictions As a consequence of reservoir modelling and history matching the 1996-2001 production, the oil production has a sharp decline, as water arrives early. The initial well start-up is staggered to maximise of oil/gas production within plant capacity constraints. HP, Test and Total capacities show the basis for generating the profiles. Adapting to existing facilities – or when designing new – these are guidelines. Maximum oil capacity shall be in the range 6500– 9000 Sm3/d.
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Yme Water Production (sm3/d) - Stream Days 14 000
12 000
Gamma PW
10 000
Beta PW Total PW
8 000
HP Capacity Test Capacity
6 000
Total Capacity Gamma PW ESP
4 000
Total PW ESP GE 2 000
01.sep.19
02.mar.22
31.aug.24
02.mar.27
01.sep.29
02.mar.32
01.sep.34
Figure 5-2 Yme Produced Water profile and capacity restrictions In the figure, water profiles for Gamma and total production are shown for simulations using Gas Lift or ESP’s on Gamma East. Although use of ESP’s is planned, these are expected to fail at regular intervals, so the figure above show the range of expected water production rates. As can be seen from the figure above, the produced water design capacity requested/ shown is higher than the profiles show (for HP, Test and total capacity). If significant cost savings can be made by reducing ‘spare’ capacity, reduced capacities shall be proposed by contractor.
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Yme Liquid Production (sm3/d) - Stream Days 20 000 18 000 16 000 Gamma Liq
14 000
Beta Liq 12 000
Total Liq HP Capacity
10 000
Test Capacity 8 000
Total Capacity
6 000
Gamma Liq ESP GE Total Liq ESP GE
4 000 2 000 01.sep.19
02.mar.22 31.aug.24
02.mar.27
01.sep.29
02.mar.32
01.sep.34
Figure 5-3 Yme Liquids Production profile In the figure, profiles for Gamma and total production are shown for production using both Gas Lift and ESP’s on Gamma East. Althoughuse of ESP’s is planned, these are expected to fail at regular intervals, so the figure above show the range of expected water production rates. As for produced water profiles the capacities quoted are higher than the shown Yme requirements. The gap will cater for uncertainty in well performance. If significant cost savings can be made by reducing ‘spare’ capacity, reduced capacities shall be proposed by contractor.
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Produced Gas and Gas Lift Rates with ESP's in Gamma East (Sm3/d) - Stream Days 1 200 000
1 000 000 Gamma Gas 800 000 Beta Gas Total Gas 600 000
HP Capacity Test Capacity
400 000
Total Capacity Max Total Capacity Min
200 000
01.sep.19 02.mar.22 31.aug.24 02.mar.27 01.sep.29 02.mar.32 01.sep.34
Figure 5-4 Gas Rates for Yme including Lift Gas - ESP's used on Gamma East
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Produced Gas and Gas Lift Rates with Gas Lift in Gamma East (Sm3/d) - Stream Days 1 200 000
1 000 000 Gamma Gas 800 000 Beta Gas Total Gas 600 000
HP Capacity Test Capacity
400 000
Total Capacity Max Total Capacity Min
200 000
01.sep.19 02.mar.22 31.aug.24 02.mar.27 01.sep.29 02.mar.32 01.sep.34
Figure 5-5 Gas Rates for Yme - Gas Lift used to lift all wells (incl. Gamma East) The two previous figures show gas Rates for Yme (Associated Gas plus Gas Lift Gas). The first figure with the lower gas rates are based on ESP’s on Gamma East peaks at 900,000 Sm3/d. The second profile use Gas Lift as artificial lift method for all wells, including Gamma East, and require a maximum gas rate of 1,100,000 Sm3/d. The plant shall be designed to enable the higher rate. However, if there are existing plant capacity restrictions which still allow the lower rate, reducing the ultimate gas capacity shall be discussed with company. The gas plant shall allow for all produced gas to be re-injected, using Water Alternating Gas injection in C-5 and C-6 (WAG). The gas rates in Figure 5-4 and Figure 5-5 exceeds the stipulated total capacity figures. This is due to thein simulation applying a regularity factor of 0.97 for the wells that is not included these stream day rates.
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Yme Water Injection Rates (sm3/d) Stream Days 14 000
12 000
10 000 Gamma WI Beta WI
8 000
Total WI Total Capacity
6 000
Gamma WI ESP GE Total WI ESP GE
4 000
2 000
01.sep.19
02.mar.22
31.aug.24
02.mar.27
01.sep.29
02.mar.32
01.sep.34
Figure 5-6 Yme Water Injection Profiles In the figure, profiles for Gamma Water Injection are shown for production using both Gas Lift and ESP’s on Gamma East. Although use of ESP’s is planned, these are expected to fail at regular intervals, so the figure above show the range of expected water production rates. The capacities quoted are higher than the shown Yme requirements. If significant cost savings can be made by reducing ‘spare’ capacity, reduced capacities shall be proposed by contractor. Yme has three pre-drilled water injectors, one in Beta East, and two in Gamma West. The Gamma injectors can also be used to inject gas in a WAG regime. In 2019-2020, two additional water injectors will be drilled: one on the Gamma East flank and one in Beta North. For Gamma and Beta fields, simulations indicate that Produced Water Reinjection gives a satisfactory reservoir sweep. As the rapid pressure decline in B-3H production history indicates, Beta North is the only segment in Yme that is not supported by a strong aquifer. The injection strategy on Beta North is different, with additional water injection for pressure maintenance. The unproduced Gamma North East segment is also expected to require more water injection than the other Yme segments.
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Gas Injection Profiles (Sm3/d) - Stream Days 600 000
500 000
400 000 Gamma C5 GI 300 000
Gamma C6 GI Total Capacity
200 000
100 000
01.sep.19
02.mar.22
31.aug.24
02.mar.27
01.sep.29
02.mar.32
01.sep.34
Figure 5-7 Yme Gas Injection Profile The figure above show Injection gas rates, alternating in WAG wells C-5 and C-6 in the Gamma West formation.
5.3
Pressure Profiles
5.3.1
Production Wells Gamma production (platform) wells will operate at close to the Yme production facility HP separator operating pressure (approximately 10 barg). Subsea wells on Beta will work against the backpressure of the topsides plant and pipeline. Expected wellhead pressure for Beta on high gas lift rates are in the area of 35 – 50 barg. Reduction of lift gas rates or one well operation will see this reduced with up to 20 bar. Slugging is expected in operation. the pipeline and riser, especially for low production rates with low/ without gas lift
5.3.2
Injection Wells Statoil experience with gas and water injection experience in Yme Gamma West was from well A-5. The well was cemented and perforated. The injectivity test with water proved low injectivity. The well was for a period on gas injection and in 1998 due to insufficient quality of the processed water, produced water had to be injected in this well. The total dissolved solids in the produced water is 196 000 ppm.
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A-5 was: On continuous gas injection Jan 97 – Jun 98 On continuous water injection Jul 98- Jan 2001 The gas injection pressure in Statoils A-5 well stayed below 250 bar and water injection pressure is generally below 200 bar with exception of a few short periods. Experience from this well has been used in simulating performance of YND injection wells. As seen in Figure 5-8 tubing injection pressure in WAG wells C-5 and C-6 is mostly below 150 bar when injecting water, with an exception of first day after
converting from gas to water in WAG injectors. Injection pressures from Gamma West well C8 and the two Beta injectors is lower.
Figure 5-8 Water Injection pressure and rates for wells C-5 and C-6
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Figure 5-9 shows tubing head pressure (THP), and gas injection rate in wells C-5 and C-6 which are injectors in Gamma West used for WAG injection. As can be seen from the figure, the gas injection pressure is mostly below 200 bar (except first day after converting from water to gas). Water injection pressures for the remaining wells on Gamma East (C-8), Beta East (D-3H) and Beta North are lower than for the Gamma West wells.
Figure 5-9 Gas Injection pressure and rate for wells C-5 and C6
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5.4
Temperature Profiles Modelling results of the existing wells and subsea structures to determine flowing pressures and temperatures have been made. Displayed results(Figure 5-10 and Figure 5-11) are shown for given production profiles.
Figure 5-10 Flowing temperature for a selection of Gamma wells
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Figure 5-11 Flowing Temperature for Beta Production Wells Estimated arrival temperatures of Beta fluid arriving gamma topsides were modelled for Yme Future based on existing subsurface equipment with approximations as described in reference 29, combined with external flow assurance input (reference 40). Case Arrival Temperatures (°C) st High Production production), (1 Low watercut 42 °C High Production (Year 2), Medium/ High Watercut 55 °C One Well Operation (Year 2), Medium/High Watercut 52-57°C Two Well (Late Production), High Watercut 65°C One Well (Late Production), High Watercut 34-65°C Note 1: High potential for slugging with significant temperature variations
Table 5-1 Indicated Beta Production Flowline Arrival Temperature
Noted fromwill thehave tablearrival above temperature is that for cases with low water cutappearance or low production in general below the 42°C wax temperature, and will require operational management, typically wax inhibitor injection.
5.5
Closed in Tubing Head Pressures Closed in tubing head pressures have been determined based on the reservoir pressure when drilling the wells for the Yme redevelopment project in 2009 and 2010. These pressures are close to the virgin pressures recorded at the initial development of the Yme field in the 1990’s, as can be se en below. Any further Page 33 of 119
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natural recharging or over injecting bringing the reservoir pressure equal to or above Virgin pressure is unlikely, therefore the Reservoir pressure recorded in 2009 is used. A range of possible drive mechanisms may be used: natural drive, gas lift (assuming tubing filled with gas) and Electrical Submersible Pumps (ESP). The wells and subsea equipment hasbeen designed to these specifications. Recorded Reservoir Pressure
Reservoir Depth
Virgin Reservoir Pressure (1997)
(m TVD MSL)
bara
(2009) bara
Beta East
3258
363
343
Beta North West
3287
363
-
Gamma North West
3178
363
-
Gamma South East
3276
363
318
Gamma South West
3210
363
318
Reservoir Segment
Table 5-2 Production Well BHP Analysis Parameters
Production Well
Reservoir Pressure (2009) CITHP (bara)
Beta East Beta North West
104 -
Gamma North West
79
Gamma South East
-
Gamma South West
79
Table 5-3 Preliminary Max CITHP - Natural Drive and Gas Lift
The design tubing pressures are 345 bara (5000 psi). The ESP dead head pressures were maintained below this limit to prevent overpressure. Gas Lifted wells will be subject to potential maximum Gas Lift pressure.
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6
Production Chemistry The following production chemistry data represent the basis for developing control and mitigation strategies to ensure trouble free flow of fluids in the production system and secure continuous production of the field.
6.1
Pressure, Volume and Temperature Data The following reservoir fluid data have been derived from PVT analysis of well test fluids and are utilised in the reservoir models. Fluid Property
Yme Beta
Yme Gamma
API grade, °API
37.07
37.07
Oil Formation Volume Factor at Initial Press, Sm³/Sm³
1.25
1.25
Oil Viscosity at Initial Reservoir Conditions, cP
0.71
0.71
1.4504*10-5
1.4504*10-5
Gas Viscosity at Initial Reservoir Conditions.
0.050
0.048
Gas Density @ standard conditions kg/Sm³
1.45
1.45
Gas Expansion Factor 1/Bg Sm³/Rm³
262
257
Reservoir temperature, °C Reservoir temperature datum, mRKB
114 3210
114 3210
Oil Compressibility, 1/bar at Pb
Table 6-1 Reservoir Fluid Data
6.2
Crude Oil Analysis Three crude oil compositions have been selected to represent the Gamma and Beta reservoir fluids (reference 12, 13). With the addition of a higher GOR well in Beta North West after a couple of years, two compositions are given here to allow assessment of flow assurance and any topsides impact for the different fluid composition. The Soave-Redlich-Kwong equation of state (SRK) with Peneloux volume correction was found suitable to match to welltest data. A common 22 component EOS characterisations with 12 C7+ pseudo components were used for all Yme PVT regions and tuned to match the available separator tests, single flashes and saturation pressures.
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Item Nitrogen
Units
Yme Gamma W
Yme Beta E
Yme Beta NW
mole %
1.163
1.042
1.377
Carbon Dioxide
mole %
1.061
1.214
1.195
Methane
mole %
17.340
16.373
17.929
Ethane Propane
mole % mole %
4.773 9.006
4.604 8.358
4.616 8.818
Iso-Butane
mole %
1.703
1.538
1.650
n-Butane
mole %
5.406
5.434
5.963
Iso-Pentane
mole %
2.132
2.317
2.440
n-Pentane
mole %
2.938
3.056
3.199
Hexanes
mole %
3.682
4.027
3.928
C7
mole %
6.201
6.071
5.831
C8
mole %
6.456
5.859
5.821
C9
mole %
4.345
3.906
3.989
C10-C12
mole %
7.893
7.960
7.561
C13-C15
mole %
6.053
6.215
5.845
C16-C18
mole %
4.642
4.852
4.519
C19-C21
mole %
3.560
3.788
3.493
C22-C25
mole %
3.490
3.792
3.457
C26-C29
mole %
2.450
2.726
2.453
C30-C35
mole %
2.376
2.722
2.411
C36-C45
mole %
1.992
2.387
2.062
mole %
1.337
1.758
1.443
C46-C80
Table 6-2 Reservoir Fluid's Composition (HYSYS input format)
Separate compositions were also created for Gamma South East (reference 13), but will not be used for design, as there are few/ no wells in these areas. Although main design shall be based on well profiles as given in Appendix 1, sensitivities to this design should be performed with Gamma W only and Beta E only composition to ensure process design is robust. The GOR for these compositions are from 61.3 Sm3/ Sm3 for Gamma West, to 54.4 Sm3/ Sm3 for Beta East. Beta North West has a GOR of about 63 Sm3/ Sm3.
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Mol wt Density g/mol g/cm³
Crit P bara
Acentric factor
Normal Tb °C
Vol. Trans -
N2
28.014
Crit T °C 146.950
33.94
0.0400
-195.750
-8.44E-04
CO2
44.010
31.050
73.76
0.2250
-78.500
-2.76E-03
C1
16.043
-82.550
46.00
0.0080
-161.550
-5.70E-04
C2
30.070
32.250
48.84
0.0980
-88.550
-2.39E-03
C3 iC4
44.097 58.124
96.650 134.950
42.46 36.48
0.1520 0.1760
-42.050 -11.750
-4.61E-03 -6.65E-03
nC4
58.124
152.050
38.00
0.1930
-0.450
-7.16E-03
iC5
72.151
187.250
33.84
0.2270
27.850
-9.97E-03
nC5
72.151
196.450
33.74
0.2510
36.050
-1.11E-02
C6
85.879
0.6647 234.250
29.69
0.2960
68.750
-1.64E-02
C7
94.878
0.7345 259.863
32.17
0.4646
91.950
-8.42E-03
C8
107.076 0.7589 281.821
29.32
0.5001
116.750
-1.34E-02
C9
120.824 0.7762 302.811
26.46
0.5394
142.250
-1.95E-02
C10-C12
146.529 0.7973 336.831
22.54
0.6131
187.182
-2.96E-02
C13-C15
189.411 0.8233 383.802
18.80
0.7272
246.415
-3.98E-02
C16-C18
235.803 0.8442 427.101
16.61
0.8421
298.239
-4.22E-02
C19-C21
275.503 0.8617 461.011
15.59
0.9335
337.514
-3.71E-02
C22-C25
323.271 0.8788 498.667
14.78
1.0342
379.419
-2.60E-02
C26-C29 C30-C35
379.160 0.8958 539.405 447.384 0.9134 586.167
14.18 13.75
1.1372 1.2394
422.707 465.017
-7.71E-03 2.00E-02
C36-C45
552.878 0.9360 653.928
13.43
1.3392
520.386
7.03E-02
C46-C80
768.286 0.9719 786.350
13.34
1.2630
617.668
1.85E-01
Comp.
Table 6-3 SRK-P Parameters for Yme EOS model
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6.2.1
Miscellaneous fluid properties
6.2.1.1
B TE X content as measur ed in 2001
6.2.1.2
Benzene 2.44 g/m Toluene 1.07 g/m Xylene 0.25 g/m
3 3 3
Mercury No analysis of elemental Mercury has been identified from previous production. Trace amounts has been measured in scale material retrieved from one of the production wells, but it is not known in what state this mercury was in (Hg0, Hg2+, etc.)
6.2.1.3
Naphtalenes The Yme crude has no Naphthalene issue.
6.2.1.4
NORM Yme formation water contains about 100 mg/l Barium and 755 mg/l Strontium. In the event that sulphate scale with these salts form it is likely there would be NORM associated with this.
6.2.1.5
Typi cal well clean-up and treatment fluids
Scale inhibitor Acids – probably acetic/ formic acid blend Asphaltene dissolver
At present existing wells are filled with Base Oil
6.3
Dead Crude Assay and Viscosity Data Reference 8 presents dead crude dynamic viscosity data, evaluated at a range of shear rates and over a range of 10 to 40 °C. Dynamic Viscosity (cP)
Shear Rate -1 s
10 °C
20 °C
30 °C
40 °C
209
15.2
4.1
-
-
298
14.7
4.4
2.5
-
427
13.9
4.6
2.7
2.0
611
12.9
4.5
2.7
2.1
875
11.7
4.6
2.8
2.2
1252
10.6
4.5
2.8
2.2
1793
9.6
4.5
2.9
2.2
Table 6-4 Dead Crude Viscosity Data
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The following table (Table 6-5) has been assembled from the crude oil assay data in Reference 11. Fraction
°C
Yieldoncrude Yieldoncrude API Gravity at 60/60°F Specific Gravity at 60/60°F Densityat 15°C ReidVaporPressure(RVP) Watercontent Sulphur Mercaptansulphur Nitrogen BasicNitrogen HydrogenSulphide
mass% vol% °API kg/l kPa mass % mass % mg/kg mg/kg mass% mass%
Viscosity at 20°C cSt Viscosity at 50°C cSt Viscosity 80°C at cSt Viscosity at 100°C cSt Viscosity 135°C at cSt Cloud point °C Cold Filter Plugging Point °C Freezing point °C Pour point °C Flash point °C Wax content mass % Smoke point mm Aniline point °C TotalAcidNumber mgKOH/g Cetane index (D-976) CalculatedCetaneIndex(CCI)(D-4737) Cetane number Watson K-factor Research Octane Number(RON) MotorOctaneNumber(MON) n-Paraffins mass % i-Paraffins mass % Naphthenes mass % Aromatics (incl. benzene) mass % Aromatics - FIA vol % Aromatics - HPLC mass % Benzene mass % Naphtalenes vol % Asphaltenes mass % n-Pentane insolubles mass % ConradsonCarbonResidue(CCR) mass % Ash mass % Vanadium mg/kg Nickel Sodium Salt as NaCl Refractive index at67°C Distillation D-86(50%) Copper Corrosion Penetration 25°C at
mg/kg mg/kg mg/l °C
Whole Crude
C5-65
4.50 5.61 37.8 88.3 0.8357 0.6438 0.8353 0.6438 63.8 122 0.53 0.18 <2 940
65-90
90-150 150-180 180-240 240-320 320-375 375-420 420-525 525-565
3.79 10.08 4.23 10.77 65.2 56.6 0.7194 0.7523 0.7192 0.7521 31.1
5.10 10.83 15.93 5.45 11.16 15.84 49.7 43.0 36.9 0.7811 0.8111 0.8404 0.7808 0.8108 0.8400
<0.001 <0.001 < 2 < 2 <1 <1
0.002 < 2 <1
0.052 < 2 <1
9.66 9.33 32.0 0.8652 0.8648
0.06
6.89 16.80 6.50 15.49 28.1 24.6 0.8865 0.9066 0.8860 0.9061
0.19
9 198 <0.001 0.007
0.24
570 0.018
0.31
1270 0.034
375+
525+
565+
3.31 37.47 13.78 10.47 2.96 33.78 11.79 8.83 20.1 21.0 13.3 11.2 0.9336 0.9276 0.9771 0.9916 0.9331 0.9271 0.9765 0.9910
0.44
2980 0.070
0.38
0.54
0.59
2700 0.065
*ND 6.81 3.04
1.12 0.80
1.91 1.22
4.97 2.56
15.4 5.83 2.22
3 <10 6.7
<10
15.0 4.18
<-51 -15 12 <-40 - 18 9 <-60 -49.5 -51 -15 12 27.5
30
44.7 51.7 8.48 25.2
42
NES *
148 299 17.2
39
188 96.2
>45
487
33
27.02 3.3 54.2 59.6 71.1 79.7 87.8 94.2 98.8 93.8 96.8 97.2 0.05 0.10 0.13 0.03 0.14 0.31 0.22 42.9 51.7 52.5 43.8 55.7 64.7 46.3 52.8 58.6 11.9 12.0 11.9 11.9 11.7 11.7 11.6
0.35
0.03 32.5 37.2
74.8 66.0 73.0 64.8 49.5 25.3 20.4 19.3 42.0 24.6 23.3 26.0 7.3 45.8 45.5 37.8 1.3 4.3 10.8 16.9 14.4
16.9 28.2
3.4
30.8
0.1 0.01
2.24
<0.1
<0.1
0.9
0.1
2.0
<0.1 <0.1 <0.1
0.6 190
3.1 5.0 2.2
<0.1 <0.1
0.1
2.4
1.486
1.503
1.503
1.00 7.7 13.5 0.040 6.2
2.60 9.2 17.4 0.090 8.4
6.7
8.9
> 300 161 207 1A 1A
1.463 1.474 273 333
0.1mm
280
177
(1): Calculated density for 525+ and 565+ NES * : not enough sample * ND: not detectable
Table 6-5 Yme Crude Assay Data
Page 39 of 119
3.50
0.110
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6.4
Formation and Sea Water Data Compositions of Yme formation water and sea water are presented below (see also reference 1). Water analysis (mg/l)
Ion
9/2A–- 1
Na+
40825
K+
1140 2+
Mg
908
2100
2+
Ca
9/2 1 –
42870
370
2070
28480
1410
26700
435
Sr2+
723
755
7
Ba2+
100
72
0
2+
123
60
0
Fe -
Cl
121000
SO42-
120500
56 -
HCO3
420
TDS Density (g/cm3)
Sea Water
11180
20310
< 15
2800
726
150
195867
194696
36662
1.135
1.134
1.025
Table 6-6 Formation and Seawater Compositions
6.5
Hydrogen Sulphide and Carbon Dioxide H2S is formed by the metabolic activity of sulphate reducing bacteria, SRB, or is naturally occurring in the reservoir. Since the Yme reservoir does not contain any significant amounts of naturally occurring H 2S, it can only be produced by SRB activity. In the oil field this occurs when sea water containing sulphate is introduced to the reservoir fluids allowing the SRB's sufficient nutrients and growth conditions to generate H2S. When Statoil operated Yme, no H2S was reported to be produced with the fluids or gas. Sea water injection was limited and none of it was reported to be produced back in any of the wells. Therefore it is not likely that any H2S would have been back-produced either. A study was conducted by Oil Plus (reference 23) which looked at the injection of the following source waters after being supplied with relevant Yme data:
Raw (aerated) water De-aerated seasea water Co-mingled sea water and produced water Produced water Because of the high reservoir temperature, 108-114°C, and high salinity, ca. 200 000 mg/l (TDS), the study indicates that the souring potential is generally low.
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Table 6-7 summarise the results. Injection Water Scenario Raw sea water injection Deaerated sea water Commingled sea water and produced water Produced water injection only
Souring Potential Low/moderate Low Low
Very low
Table 6-7 Injection water souring potential Shock dosing and continuous injection of Biocide should be planned for in the process and/or water treatment system. Reservoir souring is possible during field life as a result of seawater injection if the option for future installation is exercised. The process plant should be designed for sour service in the event that earlier seawater injection and possible sea water injection in the future lead to higher H2S levels. CO2 content of reservoir fluid is given in section 6.2. CO2 flashing from saturated Produced Water may lead to high CO2 concentration in degassing lines, and elevated CO2 concentrations in gas plant towards end of field life when oil production is low and water production high.
6.6
Wax Wax content and associated properties have been measured on oil from 3 exploration wells by Statoil; 9/2 1, 9/2 3 and 9/2 4S. The wax properties are based on an evaluation of these samples (reference32)
6.6.1
Wax Appearance Temperature For design purposes, the Wax Appearance temperature to be used is 42°C.
6.6.2
Pour Point For design purposes, the Pour Point to be used is -2°C. Testing conducted in 2014 by Kernow Analytical Technology Ltd. indicate that WAT (and corresponding melting temperatures) – especially for Beta f luid – may be somewhat lower than indicated above. Due to the age of the samples (15 years) and uncertainty as to sampling conditions, the design shall be based on the figures above. The use of pour point depressant in the initial production phase, with verification measurements of the crude will be considered as part of flow assurance work.
6.7
Asphaltenes
It is not expected that asphaltene flocculation will occur as a function of pressure depletion at the reservoir temperature of 103 °C. Asphaltene flocculation has been observed in laboratory tests with the addition of lift gas, and is therefore a risk for Beta production. Asphaltene inhibitor injection quills are located in gas lift supply subsea, upstream x-mas tree, and dedicated injection facilities shall be available for use during gas lift operation. With Gas Lift now being chosen lift strategy for Gamma West, and optional for Gamma East wells, Asphaltene injection and distribution facilities shall reflect this. Optimal injection point is downhole, upstream of gas lift valve.
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Asphaltenes could be experienced in the event that producing wells experience injection gas breakthrough. In such a case stimulation/ flushing with solvents might be required. See also reference 51.
6.8
Scale There is a high potential for scaling at Yme, in the wells, in the reservoir and in the production facilities;
Barium and strontium Sulphate forms when mixed with seawater, Carbonate scale forms with changing pressure and temperature, Iron scale deposits may also occur in the well. Scale control will be a combination of continuous scale inhibitor injection, scale squeezes and acid treatments. Continuous scale inhibitor injection is required upstream of ESPs, upstream of the production chokes and in the processing facilities where (produced and fresh) water of different compositions are mixed and subjected to pressure and temperature changes. Details can be found in reference 1. Scale prediction results suggest that the injection of produced water gives the lowest barite (BaSO4) scale saturation index. Under seawater only injection, moderate barite and anhydrite (CaSO 4) scaling is expected when the injected seawater reaches the producers. The scale deposition near the wellbore formation can be prevented by scale inhibitor squeeze treatments. If relevant, Produced Water shall be kept physically separate from Seawater in the topsides injection plant Regular scale inhibitor squeezes are required for Yme to control both calcite and barite scale deposition in the near wellbore formation (Ref51). Scale inhibitor should also be added into the produced water to prevent scale deposition on the surface facilities.
6.9
Hydrate Formation
6.9.1
Hydrate Formation on Gamma and Beta PVT sim, version 182, was used to produce the hydrate formation curves from Yme Beta with various salt concentrations. Points to note are: The formation water at Yme has high salt concentration and act as an inhibitor itself. The formation water is characterised by very high salinity and high content of Calcium. The level of Barium was uncertain at the time of hydrate simulation. This was due to contaminated samples, and potential error in the analytical method used. Barium value is confirmed to be below 100 mg/l. For more details on the study reference is made to “Yme Hydrate Manual” (reference 6)
6.9.2
Main Hydrate Conclusions From reference 6 the main conclusions can be summarised as follows: There is a potential for Yme fluid to create hydrates prior to producing formation water. The potential for forming hydrates is low when producing formation water, but increases again if seawater concentration increases in the production fluids (injection water recycle in reservoir), Facilities should be provided to permit hydrate inhibition of the production, gas injection and service lines,
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Hydrate temperature for pure water and reservoir fluid from Gamma West, Sandnes formation, at bubble-point is approximately 13 °C. The effect of the salt concentration brings the hydrate equilibrium temperature down to 1 °C, For the Beta East, Sandnes formation, the hydrate temperature formation is uncertain (suggest 23 °C). But the study concludes the formation water could bring the hydrate equilibrium temperature down to below 6 °C, Hydrate risk in a gas-lift situation shall be considered. Hydrate mitigation procedures associated with Scale squeezes in Beta
wells must be developed
6.9.3
Hydrate Strategy Hydrate procedures will be prepared at a later stage as part of flow assurance considerations in the design phase. (Reference35). Methanol has been selected as the primary inhibitor. Yme equipment shall be designed to withstand use of Methanol.
6.9.4
Hydrate Curve The following curves should be used as guideline together with the Yme Hydrate Manual (reference 6). Customized Plot 120
Beta Fluid 10% Water Cut 100
─ 100% Formation Water
80
─ 50% formation Water; 50% Sea Water
a r a
b , e r u s s e r P
60
─ 100% Sea Water
40
20
0 0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
Temperature, °C
Figure 6-1 Hydrate Curves for Yme Beta Fluid
6.10
Separation Issues When Yme was last produced, the license was penalised on oil price due to high salt concentration in the final product. The Yme separation process should be designed to ensure export oil specification is met. (Table 10-1)
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6.10.1
Salinity The salinity of the formation water is high. The chloride content is in the order of 120,000 ppm. Good water/oil separation is necessary to avoid reduced sales prices of the crude due to the salinity of the residual formation water in the export crude. Due to this high salinity of the formation water, the quality of the oil is sensitive to BS&W.
6.10.2
Emulsions and Foams Statoil experienced formation of stable emulsions in the separators. Laboratory tests and production experience confirmed the emulsion problem. Heating and use of chemical is required to obtain a high quality sales product. The very high salinity of the produced water, results in high salt content under normal BS&W specification. Heating subsea tieback to allow Inlet Separator temperature to approach 80°C is required. Limited emulsion studies have been conducted, see reference 24. Foam inhibitor injection shall be allowed for; especially as gas lift is required already during first production year. Available information does not indicate that this was an issue when Yme was produced previously. Low shear choke valves could be considered to reduce severity of emulsions.
6.11
Corrosion and Materials There is a corrosion risk with Yme fluids due to the presence of CO 2, possible H2S and high salinity, combined with a reservoir temperature of 110°C. Several corrosion study reports are available from the srcinal Yme development, for example reference 7. The plant shall be designed for sour service. The Beta pipelines are made of carbon steel, and corrosion protection shall be designed accordingly.
Page 44 of 119
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01
6.12
Chemical Injection Requirements In the previous phase of the Yme project, chemical selection and qualification were carried out by Nalco with support from independent laboratories. The results of this process are presented in the following three tables. Information from tables can be used for equipment design and system verification, although prior to start-up, the chemical selection will be reviewed. Information below is a starting point. The actual storage capacities may be adjusted in agreement with Company to suit existing facilities.
Chemical Type
Corrosion Inhibitor Nalco FX2371
Scale Inhibitor Nalco FX2504
Methanol
Asphaltene Inhibitor
Injection Location Sub-sea manifold
In all wells, upstream ESP Sub-sea manifold for extra protection in pipeline All well trees Sub-sea manifold for pipeline protection To lift gas at well heads
Dosage (Mixing Fluid) 10 – 200 ppm of Qliquid Target 100ppm residual in water phase 5 – 100ppm of Qwater
40ppm on Qwater
22 cSt (40C) 10-50 4.6 cSt (40C)
Specific Gravity 1.1 – 1.2 @ 16°C
Hydrate resistant
Carbon Steel
Hydrate resistant
100 ppm of Qoil 20-100 ppm of Qoil
100 – 1000ppm of Qoil 50-300 ppm of Qoil
Comments
1.1 @ 16°C 1.1 – 1.3 @ 16°C 1.205 @ 15°C
Injection rate of 3 1m /h for start-up and valve equalisation. 1-50
0.91 @ 16°C
32 cSt (40C) Sub-sea manifold
Material Incompatibility Carbon Steel C1018, Nitrile, Neoprene
Methanol: 1 – 30% Qwater
Nalco FX1507 Wax Inhibitor Flexoil WM2200
Viscosity cP 10-100
5 – 500 <100 cP (0C)
0.8 - 1 @ 16°C 0.95 @ 20°C
Nitrile, Neoprene, EPDM, Viton, TFE, MDPE, HDPE Hold
No fluids so recommendation based on knowledge of similar systems For potential start-up problems, low Beta arrival temperature, and in conjunction with Oil Offloading.
Table 6-8 Subsea Chemical Injection Requirements For a future seawater treatment plant to facilitate water injection, the following chemicals shall be allowed for. Chemical Type
Biocide Nalco EC6633A
Injection Location Upstream de-aerator
Dosage (Mixing Fluid) 500 - 1000ppm of Qwater (batch)
Viscosity cP 5-30
1.4 cSt (40C)
Oxygen scavenger Nalco EC6351A
Downstream de-aerator
Chlorination
1 – 100 ppm of Qwater.
5-20 2.5 cSt (21C)
Specific Gravity 1.0 – 1.1 @ 16°C
1.06 @ 20°C 1.3 – 1.4 @ 16°C 1.28 @ 15°C
Material Incompatibility C steel, Nitrile, Neoprene, EPDM, Viton
Comments
Do not use Al, C-steel, brass C steel,
Seawater Lift Pumps
Table 6-9 Water Injection System Chemical Injection Requirements
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Chemical Type
Injection Location At manifold for Gamma wells At riser outlet for Beta wells upstream choke
Dosage (Mixing Fluid) 10 – 100 ppm of Qtotal
Antifoam Nalco EC9242A or FX2165
At manifold for Gamma wells At riser outlet for Beta wells
1 – 50 ppm of Qtotal
Corrosion inhibitor Nalco FX2371
At manifold for Gamma wells
Deoiler Nalco EC9028B
Demulsifier Nalco FX2134 or DVE4Z005
Biocide Nalco EC6633A
Scale inhibitor Nalco FX2504 Methanol
Asphaltene Inhibitor Nalco FX1507
Viscosity cP 10 – 100
16-34 cSt (40C) 10 – 100 ppm of Qtotal
Specific Gravity 0.80 – 0.95 @ 16°C
0.938 @ 16°C
Material Incompatibility C steel, Nitrile, Neoprene, EPDM, TFE, MDPE
5 – 30 2-10 cSt (40C)
0.85 – 0.95 @ 16°C 0.83-0.89 @ 16°C
10 – 100 ppm of Qwater 100 ppm of Qwater
10 – 100 22 cSt (40C)
1.1 – 1.2 @ 16°C 1.1 @ 16°C
Carbon Steel C1018, Nitrile, Neoprene
Downstream all separators Additional injection quill downstrea m hydrocyclones At manifold for Gamma wells At riser outlet for Beta wells In all wells, upstream ESP
1 – 100 ppm of Qwater
400 – 1000
1.0 – 1.1 @ 16°C 1.19 @ 20°C
Copper, Carbon Steel C1018, Brass, Buna-N, Natural rubber, Aluminium, Ethylene propylene, Mild steel
1 – 100 ppm of Qtotal
<600 cP (20C)
100 – 1 000ppm of Qwater
5-30 1.4 cSt (40C)
1.0 – 1.1 @ 16°C 1.06 @ 20°C
C steel, Nitrile, Neoprene, EPDM, Viton.
5 – 100ppm of Qwater 40ppm on Qwater
10 – 50 4.6 cSt (40C)
1.1 – 1.3 @ 16°C 1.205 @ 15°C
Carbon Steel
All Gamma well heads
1 – 30% of Qwater
21 @ 20°C 35 @ 5°C
0.8 – 1.1 @ 20°C
To lift gas at well heads, or downhole injection
100 ppm of Qoil 20-100 ppm of Qoil
1-50
0.91 @ 16°C
32 cSt (40C)
Nitrile, Neoprene, EPDM, Viton, TFE, MDPE, HDPE
Comments
From report L011B/EN/99: Mixtures of Beta (B2) and Gamma (A8) Wells were more difficult to treat than the individual streams themselves. It is recommended that the co-mingling of Beta\Gamma Wells is avoided if at all possible. No tests performed on system crude, expect low foaming tendency. Ranges based on both low cost, low active and high cost, high active products Should be same as in Beta. If material quality on topsides does not require corrosion protection, this can be omitted. Previously tests on Yme Mærsk Giant showed 35 – 45 ppm. Improved process equipment will probably lower the need for deoiler down to max 10ppm.
Should be same as in Beta
Injection rate of 1m /h for start-up, WAG change-over and valve equalisation. No fluids so recommendation based on knowledge of similar systems.
Table 6-10 Production Systems Chemical Injection Requirements
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7
Drilling and Wells High level requirements and details for the Yme drilling facilities can be found in reference 45, Basis of Design Drilling and Completion.
7.1
Well Design Principles In total six wells (4 producers and 2 injectors) at Yme Gamma and three wells (2 producers and 1 injector) at Yme Beta have been drilled, completed and temporarily abandoned. For the remaining three Yme Gamma well slots, two have 30” conductors installed and one has a 30” conductor as well as a 14” surface casing installed. There are no spare well slots at Yme Beta. Operations and design has been performed according to Repsol Policy and NORSOK D-010. For the Yme New Development project it is important to utilize all the well slots at Yme Gamma. Two of the three available slots will be drilled and completed as producers and one as an injector. The well placement and trajectory design for the future infill wells and potential sidetracks will be evaluated with respect to the best drainage strategy.
7.2
Yme Gamma The Yme Gamma wells were drilled by Jack-up rig Mærsk Giant. The derrick was skidded over to the caisson and the wells were drilled trough the caisson ’s well guides. The Wellheads and x-mas trees are located on the upper caisson deck.
Figure 7-1 Mærsk Giant Cantilever by the Yme Gamma Caisson
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Figure 7-2 Yme Gamma Caisson with x-mas trees on upper deck 7.2.1
Yme Gamma Wellbore trajectories
Figure 7-3 Yme Gamma wellbore trajectories for the existing wells
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7.2.2
Well summary 1
2
Well
Designation
Objective
MDBRT
TVDSS
Completed
9/2-C-1
Producer
Sandnes
5260 m
3265 m
8/1/2010
(ESP)
Formation
Producer
Sandnes
5231 m
3160 m
28/9/2010
5240 m
3126 m
31/12/2009
4637 m
3089 m
31/12/2009
4913 m
3457 m
27/8/2009
5448 m
3393 m
29/8/2009
9/2-C-2 AT2
Formation 9/2-C-3 T3
Producer
Sandnes Formation
9/2-C-4
Producer
Sandnes Formation
9/2-C-5
WAG Injector
Sandnes Formation
9/2-C-6
WAG Injector
Sandnes Formation
9/2-C-7
Future
14” Casing 1344 m
23/1/2010
Producer (ESP) 9/2-C-8
9/2-C-9
Notes
Future Water
Conductor
Injector
run
Future
Conductor
Producer
run
1. MDBRT – Measured Depth Below Rotary Table (Actual drilling distance) 2. TVDSS – True Vertical Depth SubSea (Vertical well depth below seabed)
Table 7-1 Gamma well summary table Detailed well information can be obtained from the RNAS Drilling & Completion group, where updated information is stored on the sharepoint site TIP in the form of end of well reports or well data handover package for the individual well.
7.3
Yme Beta The Yme Beta wells were drilled by the jack-up rigs Mærsk Guardian (top hole sections) and Mærsk Giant (remaining sections and completions) above a 3-slot subsea template which was later tied back to the Yme Gamma location. A new subsea template is required for additional wells (Beta North). This will be connected up to existing manifold through jumpers, and interface to existing design by meeting the same design parameters. Page 49 of 119
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Figure 7-4 Yme Field development, including Beta Template
Figure 7-5 Yme Beta wellbore trajectories for the existing wells
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01
7.3.1
Well summary 1
2
Well
Designation
Objective
MDBRT
TVDSS
Completed
9/2-D-1 H
Producer
Sandnes Formation
4231 m
3161 m
10/7/2010
9/2-D-2 H
Producer
Sandnes Formation
4540 m
3205 m
9/7/2010
9/2-D-3 H
Water Injector
Sandnes Formation
4150 m
3492 m
26/7/2010
Notes
1. MDBRT – Measured Depth Below Rotary Table (Actual drilling distance) 2. TVDSS – True Vertical Depth SubSea (Vertical well depth below seabed)
Table 7-2 Yme Beta well summary table Detailed well information can be obtained from the RNAS Drilling & Completion group, where updated information is stored on TIP in the form of end of well reports or well data handover package for the individual well.
7.4
Artificial Lift
7.4.1
Basis of design During pre-studies of Yme Re-Development project it was identified that artificial lift was required based on reservoir studies, experience from Statoil, economics analysis, and historical experience. Electrical Submersible Pumps (ESPs) were selected as the primary artificial lift method on both the Gamma and Beta producers. In YME Future Development Project (2012-2014) the preferred artificial lift solution for Beta was changed to gaslift. Main reason for changing artificial lift strategy on Beta was that when the wells were drilled, the reservoir showed better qualities then expected in the Yme-redevelopment. As a result of the higher quality reservoir the difference between ESP and Gas Lift was much smaller than first anticipated. As a result of changing to gas lift the production uptime will be higher, and well workover cost will be significantly reduced. The Yme New Development project hasfurther looked into artificial lift. Prosper simulations shows that it is only C1 and C7 that will have a greater production from using ESP’s as thewith artificial lift method. The other will be producing more or less the same gas lift. ESP workover cost wells will be significantly reduced compared with the artificial lift solution proposed previously.
7.4.1.1
E S P G amma ESP will be the preferred artificial lift method only in wells C1 and C7. Both these wells are located in Gamma East reservoir section, and will be supported by C8 water injection. The wells on Gamma West will be supported by the injectors C5 & C6. These wells will not be pure water injector wells as C8, but alternating gas/ water injection. Gas break though is expected to happen after 6-12 month in GSW, and GNW with very high GOR. Therefore, the other wells than C1 and C7 Page 51 of 119
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will not be suited for ESP as too high gas content in the well stream will lead to gas locking the pumps. C1 already has dual ESP installed, while C7 is to be drilled in the first campaign on Yme. C1 & C7 ESP: In C1 a dual ESP system consisting of 900 HP/900 HP upper P110 centrifugal pumps is installed. These pumps will be attempted to start. The pump curves for the two ESP pumps could be overlapping if required. For new ESP wells on Gamma. Gaslift will be backup.
Detailed specification of ESP equipment installed see Figure 7-6 and Table 7-3
Functional requirements of the ESP system: ESP Downhole: ESPs are designed to handle up to 10 % free gas at pump intake. Therefore ESP in C2-C3-C4 will not be the best solution due to high GOR in gas/water in these wells upon gas breakthrough. ESPs are designed to achieve an average run life greater than three years for dual ESP systems through the lifetime of the field. Wells have a tangent section where ESP assemblies are located (at the ESP setting depth), with the cased Dog Leg Severity (rate of turn “DLS”) not exceeding 1° per 30 m. The completion design consist of a 5 ½” tubing string with a TR -SSSV and gas lift mandrel backup on Beta. ESP systems have a full downhole instruments package with data transmitted to the platform and the ESP management system via the power cable. The ESP downhole pressure and temperature data will not be available when gas-lifting the ESP completed well. The current ESP vendor is Baker Hughes Centrilift. Centrilift shall provide ESP as a full system including the management of all the internal interfaces and supply of all the ESP equipment, test systems and wellhead/tree interface systems, ESP downhole system, power distribution system outboard of the tree ESP scope shall be managed by a dedicated focus group including the Repsol and allocated vendor/contractor staff who are involved with the ESP system or parts of it. More modelling is required to identify if the 900 HP and what pump is the best for workover in C1 and ESP in C7.
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.
Figure 7-6 ESP system topology and interface
7.4.1.2
Y me G amma G as Li ft. The C2-C3-C4 that is supported by water/gas alternating injectors C5-C6 will be using gas lift as the artificial lift method. Gas lift will be installed either with a gas lift retrofit solution just above the ESP packer with a M-SAS barrier on the annulus side, or as a full recompletion with a new gas lift completion also comprising an ASV. New gas lift completions will be completed with gas lift mandrel and ASV.
7.4.1.3
Y me B eta G as Li ft The Yme Beta wells are at present completed with ESP’s, but subsurface work indicates that similar oil reserves can be recovered by use of Gas Lift, rather than use of these. Initially the Beta wells will therefore be produced through the single Gas Lift valve in the current completion. If recompleted the ESP completion will be removed and replaced with a more purpose built Gas Lift solution, which is described in the Well Design Summary (reference 41). Detailed specification of current ESP equipment installed, see Figure 7-6 and Table 7-3
7.4.2
Detailed - Downhole ESP System as Installed The ESP sizing is defined in the ESP Downhole Basis of design report YME26168-Z-0013 (ref. 7.24). The ESP selection is based on the reviewed reservoir properties from the MWD logs during drilling of the wells. Technical specification of all ESP equipment can be found in YME-26168-Z-0370 (ref 7.19)
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7.4.3
Future ESP’s Gamma The ESP downhole architecture in C1 and C7 will be evaluated to suite the subsurface flow requirements, and designed to meet the expected ESP lifetime. We ll
C1
S yst e m
Inst a l l e d M on i t ori n g
M ot or
562 KMHX-VC 900/4100/132 44R FEREHL CL6 Dual 3 1/2" Upper 08.01.2010 Bypass with YProduction Check Lower 08.01.2010 Quest 562 KMHX-VC 900/4100/132 44R FEREHL CL6
562 KMHX-VC 900/4100/132 44R FEREHL CL6 Dual 3 1/2" Upper 10.10.2010 Bypass with YProduction C2A
C3
C4
D1
D2
Check
Lower 10.10.2010
Quest
562 KMHX-VC 1200/4500/173 66R FEREHL CL6
562 KMHX-VC 900/4100/132 44R FEREHL CL6 Dual 3 1/2" Upper 23.12.2009 Bypass with YProduction Check Lower 23.12.2009 Quest 562 KMHX-VC 1200/4500/173 66R FEREHL CL6
562 KMHX-VC 900/4100/132 44R FEREHL CL6 Dual 3 1/2" Upper 31.12.2009 Bypass with YProduction Check Lower 31.12.2009 Quest 562 KMHX-VC 1200/4500/173 66R FEREHL CL6
562 KMHX-VC 900/4100/132 44R FEREHL CL6 Dual 3 1/2" Upper 15.06.2010 Bypass with YProduction Check Lower 15.06.2010 Quest 562 KMHX-VC 1200/4500/173 66R FEREHL CL6
Upper 02.07.2010 562 KMHX-VC 900/4100/132 44R FEREHL CL6 Dual 3 1/2" Bypass with YProduction Check Lower 02.07.2010 Quest 562 KMHX-VC 1200/4500/173 66R FEREHL CL6
L o w e ra n dU ppe rS e a l
P um p
M a i nCa bl e
513SXU BB/B MCV FER M/C CUW EHL H19SB2PFSACL6D SP 44/40/60Stg562P110LSMXXSD 513SXU BB/B MCV FER M/C CUW EHL H19SB2PFSACL6D SP 44/40/60Stg562P110LSMXXSD
2/0SOLBC/7KV/DL90/HTFB/EP DM/GALV/RND
513SXU BB/B MCV FER M/C CUW EHL H19SB2PFSACL6D SP 38/38/38Stg562P155LSMXXSD 513SXU BB/B MCV FER M/C CUW EHL H19SB2PFSACL6D SP
2/0SOLBC/7KV/DL90/HTFB/EP
44/40/60Stg562P110LSMXXSD
513SXU BB/B MCV FER M/C CUW EHL H19 SB2PFSACL6 DSP 40/51 Stg 562P200LSMXXSD 513SXU BB/B MCV FER M/C CUW EHL H19SB2PFSACL6D SP 52/52/38Stg562P155LSMXXSD
DM/GALV/RND
2/0SOLBC/7KV/DL90/HTFB/EP DM/GALV/RND
513SXU BB/B MCV FER M/C CUW EHL H19 SB2PFSACL6 DSP 40/51 Stg 562P200LSMXXSD 513SXU BB/B MCV FER M/C CUW EHL H19SB2PFSACL6D SP 52/52/38Stg562P155LSMXXSD
2/0SOLBC/7KV/DL90/HTFB/EP DM/GALV/RND
513SXU BB/B MCV FER M/C CUW EHL H19SB2PFSACL6D SP 38/38/38Stg562P155LSMXXSD 513SXU BB/B MCV FER M/C CUW EHL H19SB2PFSACL6D SP 44/40/60Stg562P110LSMXXSD
2/0SOLBC/7KV/DL90/HTFB/EP DM/GALV/RND
513SXU BB/B MCV FER M/C CUW EHL H19SB2PFSACL6D SP 38/38/38Stg562P155LSMXXSD 513SXU BB/B MCV FER M/C CUW EHL H19SB2PFSACL6D SP 44/40/60Stg562P110LSMXXSD
2/0SOLBC/7KV/DL90/HTFB/EP DM/GALV/RND
Table 7-3 ESP System as installed (1 of 2)
Table 7-4 ESP System as installed (2 of 2) 7.4.4
Subsea and Surface Equipment Requirements Baker Hughes has performed a VSD study (on draft level) in Yme New Development. The new recommendation is designed to be able to operate the current installed 900 HP/ 1200 HP on Gamma. A total of 2 wells (C1 and C7) were the basis for this study VSD selected to be able to run the 1200 HP ESP on Gamma on full load require an ABB ACS 2000 or similar.
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2 VSD’s will be required to run the 2 ESP wells on Gamma. Max imum expected power output requirements from VSD is 4800/ 173 A for the 1200 HP system, and 4500 v/ 132 A for the 900 HP system to be able to run theESP’s at 100% load. The maximum total ESP system power requirement to design for is 1.4 MW for the two ESP wells if using 900 HP ESP, and 1.6 MW if 1200 HP ESP is required. The actual power requirement will be revised later in FEED after final ESP sizing/ selection has been performed. ESPs shall be monitored and controlled from the platform. All the ESP data shall
be transferred to shore for real-time online monitoring of the ESP operations and performance. This shall be done through the control system on the platform and PI. EMS (enhanced monitoring system) shall be a standalone control system interfaced to the ICSS of the platform. The Enhanced Control and Monitoring Philosophy will be developed by Repsol, and programmed by ABB/ESP supplier. Interfacing towards the ICSS will be done by TopsidesContractor/ ESP supplier.
7.5
ESP Topside Interfaces: Constractor/ Supplier shall be responsible for all cabling from VSD to XMT. Repsol shall provide the cable from Junction box to wellhead, but contractor is responsible for installation and commissioning of this cable as well as the cable from junction box to VSD. The supplier will be responsible for planning, engineering, mechanical complete, and commissioning of the VSD. The ESP supplier will support on this work. Supplier shall be responsible all hookup and commissioning PSD, ESD, and communication bus to the Control system, as will be defined in the Functional Design Specification for the EMS.
7.6
Well Clean-up The wells have yet not been cleaned up or tested. The base case has been to clean up the production wells into the test separator immediately prior to each well’s production start-up by natural flow, gas lift or ESP. The C1 and C7 wells will be cleaned up with ESP’s or natural flow , while C2, C3 and C4 will be cleaned up with gaslift or natural flow. Beta wells will be cleaned up using gaslift. The OBM/suspension fluid left downhole were compatible with the srcinal planned process equipment in the base case. Cleaning up to the process test separator will permit the wells to be evaluated in terms of deliverability and an assessment made of any reservoir damage. A well start-up/clean up strategy and following programme will be developed.
7.7
Surface Intervention The intervention philosophy is based on a Jack-Up rig. All intervention work and workovers will be conducted from drill floor. For a floating concept, intervention will be based on a hired in jack-up rig installing over a WHP.
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7.7.1
Workover requirements The Functional Requirements for the facilities define the deck space/loads, POB requirements and crane capacity required to carry out interventions and workovers. Loads from well interventions as coiled tubing will be transferred onto rig floor on the jack-up by use of a coiled tubing tension frame. Two cranes must have a lift capacity of 40Te each for sea and platform lifts to be able to lift a standard 2 3/8” coil reel of 3700m length. During workover operations the loads will be transferred through the derrick and into the jack-up.
7.8
Subsea Intervention
7.8.1
Base Case The base case for subsea wells from the 3-slot template on the Beta structure is to minimise the need for interventions in the first place, largely by choosing gas lift as lifting mechanism for Beta. Secondly it is to make use of dedicated vessels wherever possible. The following assumptions are made for the Base Case; A rig will be required for changing out tubing, Coiled Tubing work will require a rig or potentially a dedicated vessel, For Wireline work a dedicated vessel can be used, Pumping operations such as scale squeezes and acidizing will be done through the service line from the host platform.
7.8.2
Reasoning for Base Case For Tubing change out, a rig is required because of limited availability of
7.9
intervention vessels with Norwegian Aoc (Acknowledgment of Compliance) For both Coiled Tubing and wireline work a few vessels are certified for this type of operations on the NCS.
Drilling and Wells References
Ref 7.1 7.2 7.3 7.4 7.5 7.6 7.7
Document and revision number may lack on documents not yet completed and stored in E-Search. Repsol Drilling & Wells department is to be contacted if further information is required. Description and Doc no Talisman Energy Norge AS, “Well Handover Data Package, Yme 9/2-C-1”, CIMAGE Document Number 9/2-C-1 W.60.00, Revision 01 Talisman Energy Norge AS, “End of Well Report, Yme 9/2-C-1”, CIMAGE Document Number …., Revision … Talisman Energy Norge AS, “Well Handover Data Package, Yme 9/2-C-2A T2”, CIMAGE Document Number 9/2-C-2A T2 W.60.00, Revision 00 Talisman Energy Norge AS, “End of Well Report, Yme 9/2-C-2A & 9/2-C-2 AT2”, CIMAGE Document Number …., Revision … Talisman Energy Norge AS, “Well Handover Data Package, Yme 9/2-C-3 T3”, CIMAGE Document Number 9/2-C-3 T3 W.60.00, Revision 00 Talisman Energy Norge AS, “End of Well Report, Yme 9/2-C-3, C3T2 & C3T3”, CIMAGE Document Number …., Revision … Talisman Energy Norge AS, “Well Handover Data Package, Yme 9/2-C-4 T3”, Page 56 of 119
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7.8 7.9 7.10 7.11 7.12 7.13 7.14 7.15 7.16 7.17 7.18 7.19 7.20 7.21 7.22 7.23 7.24 7.25 7.26
CIMAGE Document Number 9/2-C-4 T3 W.60.00, Revision 00 Talisman Energy Norge AS, “End of Well Report, Yme 9/2-C-4, C4T2 & C4T3”, CIMAGE Document Number …., Revision … Talisman Energy Norge AS, “Well Handover Data Package, Yme 9/2-C-5”, CIMAGE Document Number 9/2-C-5 W.60.00, Revision 00 Talisman Energy Norge AS, “End of Well Report, Yme 9/2-C-5”, CIMAGE Document Number …., Revision … Talisman Energy Norge AS, “Well Handover Data Package, Yme 9/2-C-6”, CIMAGE Document Number 9/2-C-6 W.60.00, Revision 01 Talisman Energy Norge AS, “End of Well Report, Yme 9/2-C-6”, CIMAGE Document Number …., Revision … Talisman Energy Norge AS, “End of Well Report, Yme 9/2-C-7”, CIMAGE Document Number …., Revision … Talisman Energy Norge AS, “End of Well Report, Yme 9/2-C-8”, CIMAGE Document Number …., Revision … Talisman Energy Norge AS, “End of Well Report, Yme 9/2-C-9”, CIMAGE Document Number …., Revision … Talisman Energy Norge AS, “Well Handover Certificates, Yme 9/2-D 1H”, CIMAGE Document Number Yme 9/2-D-1H W.37.1, Revision A Talisman Energy Norge AS, “Well Handover Certificates, Yme 9/2-D 2H”, CIMAGE Document Number Yme 9/2-D-2H W.37.1, Revision A Talisman Energy Norge AS, “Well Handover Certificates, Yme 9/2-D 3H”, CIMAGE Document Number Yme 9/2-D-3H W.37.1, Revision A ESP Final Document package YME-26168-Z-0370 Expected ESP run life Report YME-EPT-D-0001-PSA-1421-001 YME ESP Decision support Document YME-EPT-D0010-PSA-1462-001 YME Corrosion and Materials Review YME-EPT-D-0003-PSA-1423-001 Yme Well Scale Review, 26/5/2005, Paladin Resources ESP downhole Basis of Design Report YME-26168-Z-0013 ESP Electrical loading YME-26168-E-0103 Rev B Enhanced Control and Monitoring Philosophy YME-26168-Z-0034
Table 7-5 Drilling & Wells reference documents Since the srcinal project, an updated Scale Review is available (Ref.50).
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8
Production Technology
8.1
Introduction The completion strategy was to build a robust and reliable completion. Completions cater for monitoring capabilities of installed equipment, reservoir and well performance. The important drivers with respect to the completion functionality were; Sand face completion architecture, Inflow control and management, Artificial lift requirements, Production optimisation and reservoir monitoring requirements, Flow assurance requirements: Down hole scale inhibitor injection requirements including the ability to perform frequent scale inhibition treatments to prevent scaling in the reservoir and wellbore, Lifecycle management requirements: Interventions, reservoir management and formation damage management. For future sidetracks and infill wells, the same principles will be applied, although the design will reflect technology development.
8.2
Historic Context The srcinal Yme development (Statoil) experienced several technical difficulties due to the properties of produced fluids and performance of the reservoir. The previous development concept also set some boundaries that were challenging to operate within. A large part of the Production Technology work, to date, has been to review the experience gained and documented by Statoil. The main areas of concern highlighted by Statoil were; Artificial lift o Gas lifted wells - lack of gas, limited lifting capabilities (above 60 % WC) o ESP lifted wells - short run life Production chemistry o Scale, CaCO 3 scale precipitation, formation damage o Emulsion, excessive OIW content o Salt content - corrosive environment, sales specification penalties Well testing and surveillance o Sampling limited o Rate data from individual wells limited
o Slugging problems from Beta subsea wells High workover frequency and cost o ESP failures o Well integrity due to tubing leaks o Material selection due to corrosive environment. A range of different well and completion types were tested by Statoil during the previous development. The most successful well type was the long horizontal open hole completion with ESP lift. The lessons learned were implemented in five sidetracks and nine new ESPs deployed to improve oil recovery in the final two years of production.
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The previous YME experience and learning’s were reviewed and incorporated into the well and completion design. Further experience from Statoil can be found in references 6, 7, 24, 25 and 26.
8.3
Sandface Completion and Inflow
8.3.1
Basis of Design Details of completions are given in chapter 7.
8.3.1.1
S and Failure No active sand control is considered for the wells. Previous rock mechanics tests have predicted a negligible risk of sand production through the life of the well.
8.3.1.2
S olids Pr oduction Some fines should be accounted for. Initially, solids will be produced during clean-up of the well. The table below shows gravimetric analysis of solids found in the srcinal Yme development produced water and seawater cooling system. More details on this can be found in reference 3.
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Sample
Source
Number 1
SW
Sample
Weight
Volume
Before
Weight After
Weight
Visual
Particles
Examination
litre
mg
mg
Mg
1
69.0
79.3
10.3
Yellow/transparent Silica traces 40 – 70 μm. Fair coloured oxidation particles.
2 3
SW SW
1 1
68.4 62.6
76.5 70.8
8.1 8.2
4
A1
0.5
62.6
-
-
5
A2
0.5
67.8
72.3
4.5
As #1 + some particles >70 μm. As #1 + some transparent fibre particles. “Cleaner” than # 1, 2 and 3. Particle sizes 10 – 30 μm. Very clean sample. A few silica apparent particles.
6
DEG
0.5
62.5
-
-
7
DEG
0.5
61.1
85.5
24.4
Similar to #4 but without the fibre particles.
8
A2
0.5
59.9
91.2
31.3
As #5.
9
DEG
0.5
61.8
65.2
3.4
As #1.
10
A1+A4
0.5
60.1
63.7
3.6
Varying sizes of silica apparent particles +
11
A1+A4
0.5
61.8
-
-
Similar to #4.
some metal particles 20 – 40 μm. Similar to #10 + what appears to be elastomeric material (seal material).
12
A2
0.5
58.4
-
-
13
MIX
1
57.2
74.3
17.1
As #1. Sample is covered by a milky white-yellow substance + some semi-transparent flakes (>300 μm). Traces of what appears to be oxidation particles.
14
MIX
1
58.3
-
-
As #13 but smaller content of the milky substance.
Table 8-1 Gravimetric Analysis of Solids from Original Yme Development
Average concentration of solids at the different sample locations are presented in the following table.
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Sample Location
Average Concentration mg/l
Well A1 + A4
7.2
Well A2
36
Degasser
28
Sea Water
9
Mixed Water
17
Table 8-2 Avg. Concentration of Solids from Original Yme Development Based on above information, the following parameters shall be used for design of new equipment for the topsides plant: 25 mg Sand/ Solids production per litre of produced water Average particle size of 20 μm
8.3.1.3
Inflow control and roc k face completion arc hitecture Well productivity achieved during initial drilling phase and the production phase will have a significant impact on the levels of the fluids off take. As such, skin minimisation and the scale management system shall be focus areas during field development planning. The choice data of open hole that reservoir completions is the based onresults. Yme historical production proving this solution yielded best Producer 9/2A-8 and one track on 9/2-A-2 had open hole completions. These wells had no indication of sand production and were very productive. Sand production is not expected on Yme; however some fines should be accounted for (see previous chapter). Initially, solids and debris will be produced during clean-up of the well. Reservoir engineering work confirms that long horizontal wells give the best recovery. Moreover open hole completions reduce the well construction risks and costs. On the Gamma Water Injectors a liner and selective perforation is required to control the injectivity of the planned water flood sweep pattern and seal off the middle part of the well, which has potentially reactive and unstable shales.
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8.4
Measurement, Monitoring and Sampling
8.4.1
Summary Monitoring and surveillance of the Yme reservoir and individual well performance, (well testing, down hole equipment monitoring/control), and live data to shore will play an important role in re-developing the Yme field for optimisation of reservoir performance and prolonged ESP run life with improved uptime for the wells. Key issues are: ESP monitoring (Pressure and Temperature) and control to shore, Flow assurance; Scale and asphaltene control Well integrity; Corrosion control Well testing and reservoir monitoring, Subsea well testing. Data link to provide real time data onshore The table below summarise the main components, which may be adjusted to suit existing facilities subject to company agreement;
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Case
Solution
Challenge
Frequencies
Water sampling for scale control
Water sampling at individual well head
Sampling of subsea wells. This will only be possible when wells are selectively tested.
Regularly
Well testing for
Individual well needs to
Access to test facilities, good
Monthly or
allocation, WCdetermination, gas breakthrough detection
be tested regularly separator, or main on test separator
measurement Subsea wells to be tested after scale squeeze interventions
when required.
Sand production monitoring
ESP surveillance
Calculated within the ESP software
Testing wells without ESP interruption
Sand probe at main - and test separator
Determination of the sand mass/volumes.
Sampling for analysis
Identification of the offending well(s)
Via the downhole monitoring system
Data to shore for surveillance Interfaces and integration
deployed with the ESP
into Repsol system
Subsea wells 6 monthly
Continuous
Continuous
Via Xmas tree gauges for the wellhead data Reservoir management
Data to shore for surveillance, pres., temp, rates from ESP Further data gathering during well interventions
Interfaces and integration into Repsol system
Continuous
Performance management with ESP data.
Allocate PVT properties to individual wells
Oil sampling from individual wells either from well head or from test separator
Get representative samples
Infrequently
Production management and reporting
Data to shore for surveillance
Interfaces and integration into Repsol system
Continuous
Well Integrity Testing
Regular testing tied to ESP schedules
Maintain without interference with the ESPs
Regularly
Table 8-3 Monitoring, testing and sampling requirements - Overview Page 63 of 119
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8.4.2
Well sampling Well sampling of produced water will be taken every week initially to determine water chemistry and scale potential. Based on operational experience with the wells, this frequency will be adjusted. Also, the water samples will be used to evaluate scale inhibitor squeeze performance. Hydrocarbon samples of the wells will be taken initially to establish PVT properties and how the wells compare with the overall PVT properties for the field.
8.4.3
Sand monitoring
8.4.3.1
E S P Monitoring
The formation strength of the sand on Yme is high, with no significant sand production when Statoil produced the Yme field (see chapter 8.3.1.2). The predrilled wells on Yme are part open completions and pre-slotted liners. Sand detection equipment should be installed upstream the inlet and test separators on Yme in order to detect if there is any sand production and to identify the source as early as possible.
The downhole monitoring equipment shall be installed to control the operation of the pump, recording historical data for optimization of reservoir management and continuous process improvement in the operation and further design of artificial lift and completion systems. ESPs include monitoring system connected to the bottom of the motor. This system include pressure/temperature discharge assembly above the pump discharge, with main data acquisition unit located below the lower tandem motor and connected to the power system via star point of the lower tandem motor section stator winding. The installed system does allow monitoring of the following downhole parameters: Pump Intake Pressure, Pump Intake Temperature, Pump Discharge Pressure, Pump Speed, Pump Discharge Temperature, Motor Winding Temperature, ESP Vibration, both x & y, Current Leakage, Downhole Electronics Temperature. The data transmission is via the power cable to eliminate the need for an additional penetration through the tubing hanger and the tree. Online monitoring and management of ESPs from the shore shall be facilitated through data link. Note: ESP wells were gas lift has been used as the artificial lift method. The Downhole ESP monitoring will not be available.
8.4.4
Well testing and allocation Monthly testing of each well through the test separator is the basis for the well allocation. The subsea wells will be tested together if possible or individually if the total fluid exceeds the test separator capacity, in which case production loss will occur. Test frequency of subsea wells may therefore exceed one month and will be done on an as need basis. Post and pre testing of the wells will be done in conjunction with scale squeezes Page 64 of 119
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8.4.5
Integrity and barrier testing. The integrity and the barriers of the wells will be tested according to the applicable NORSOK standard D-010 Section 15, that deals with testing of all the barriers in the well in the drilling phase and production phase. The A-annulus on all wells will be constantly monitored, and where practical the B annulus will have the capability of continuous monitoring.
8.4.6
Downhole monitoring and well intervention The wells are set either with pre-slotted liner/ swellpackers/ open completions(C2 and C-4), open hole completions(C-3) and pre-slotted liner with swellpacker to TD(C-1). The swellpacker were set across coal layers to prevent coal bits to enter the wellstream, which coulddamage the ESP’s. Table 1 below presents a summary of the lower completion for the four wells. With the present completions it is not possible to do flowing surveys with wireline tools in the hole while running the ESP’s. It is possible with another design of the flowtube/ bypass to perform such a survey when the wells are recompleted, but the risk is considered to be high. Therefore PLT’s will not be considered as an option for wells requiring ESP’s to flow. Saturation tools that will be run during shut-in conditions are an option, and will be considered on a well by well basis. For the wells with swellpackers there should be a good potential that the swellpackers acts as no flow barriers behind the liner, provided that the coal layers prevents flow. This could present a potential for setting zone isolation plugs. There are well tractors available that can pass the minimum restriction of 2.532’’ ID in the tailpipe. Potential reward/risks has to be considered for using surveillance tools run on wireline after the field is set on production.
Table 8-4 Lower Completion
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9
Subsea
9.1
Subsea Facilities and Document References The existing infrastructure described in this section is developed from Yme Redevelopment BoD rev 2 issued 15.11.2006. The subsea production system (SPS), power control system, pipeline systems and flexible riser systems are defined in the following documents and the documents referenced therein: Ref 9.1 9.2 9.3 9.4 9.5 9.6
Doc no YME-23056-Z-3006 rev 02 issued 16.10.2009. YME-23056-Z-3201 rev C issued 28.02.2009 YME-23056-U-0004 rev A issued 25.09.2009 YME-23056-U-0003 rev B issued 21.04.2008 YME-23056-U-9050 rev B issued 26.06.2009 YME-21389-Y-0185 rev Z2 issued 08.09.2009
9.7 9.8
YME-21389-Y-0041 rev Z1 issued 28.04.2010 YME-26168-Z-0282 rev A issued 02.07.2009
9.9
YME-TEN-I-0004 Rev A 09.08.2010
9.10
DNV-13PQ5FY-1 rev 1 12.01.2012
9.11
Talisman document under activity 11-024 rev 03 issued 23.02.2011 YME-21389-U-0212 rev Z1 issued 10.02.2010
9.12
9.13 9.14 9.15 9.16
9.18
YME-23056-Z-0016 rev A issued 17.06.2009. YME-23056-Z-0017 rev A issued 17.06.2009 YME-23056-U-5048 rev 02 issued 02.09.2009 YME-23056-U-5000-001 rev D issued 23.04.2009 YME-23056-U-5000-002 rev D issued 23.04.2009 YME-23056-I-6123 rev Z1 issued 28.01.2009
9.19
YME-23056-U-3001 rev A issued 28.01.2009
9.20
YME-23056-R-3005 rev A issued 07.08.2009
9.21
YME-23056-N-3012 rev A issued 06.08.2009
9.22
YME-23056-U-9072 rev D issued 11.05.2009
9.23
YME-23056-U-6005 rev Z issued 20.05.2009
9.24 9.25
YME-23056-U-6000-001 to -009 rev Z issued 22.05.2009 YME-23056-U-6010 rev Z3 issued 28.01.2009
9.26
YME-23056-E-6145 rev Z1 issued 28.01.2009
9.27
YME-23056-E-6179 rev Z3 issued 28.01.2009
9.28
YME-23056-U-6146 rev Z issued 28.01.2009
9.29
YME-23056-U-6147 rev Z issued 28.01.2009
9.17
Description YME MCS DFI Resume (Vetco Gray) Overall field lay-out drw (Vetco Gray) Overall System User’s Manual (Vetco Gray) Design Basis (Vetco Gray) User manual – Umbilical System (Vetco Gray) DFI Resume for pipe coating (Technip / Bredero Shaw) DFI Resume for subsea installation (Technip) Power Umbilical calculation & verification of selected cable design (Baker Hughes) Performance Description of Total Yme Leak Detection System (DNV) YME Subsea Flowlines and SLS Preservation Study Yme Preservation Evaluation (Technical Support) Mechanical Completion Dossier System 18 PIPELINES, CONTROL UMBILICAL AND STRUCTURES Material Selection Report (Vetco Gray) Material Philosophy Report (Vetco Gray) Design Verification Package & IRC (Vetco Gray) Tree System Scope of Supply (Vetco Gray) Tree System Scope of Supply (Vetco Gray) Functional Design Specification Wellhead Single/Dual Pressure Temperature Sensors (Vetco Gray) Manifold Functional Design Specification (Vetco Gray) ICARUS Connection Functional Design Specification (Vetco Gray) Manifold GRP Covers Functional Design Specification (Vetco Gray) Control Umbilical Functional Design Specification (Vetco Gray) Production Control System Functional Design Specification (Vetco Gray) System Scope of Supply (Vetco Gray) Software System Functional Design Specification (Vetco Gray) Master Control Station Functional Design Specification (Vetco Gray) MCS Software Functional Design Specification (Vetco Gray) Subsea Control Module Functional Design Specification (Vetco Gray) Subsea Control Module Mounting Base Functional Design Specification (Vetco Gray) Page 66 of 119
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YME-23056-E-6114 rev Z issued 28.01.2009
9.31
YME-21389-U-0004-001 rev Z2 issued 04.06.2010
Electrical Test Unit Functional Design Specification (Vetco Gray) Field Layout (Technip)
Table 9-1 Existing Yme Subsea installations document references The ESPs and submerged loading system are not a part of the subsea production facilities but are mentioned for reference. The power umbilical for actuating the ESPs is included herein.
9.2
Subsea Design Codes, Standards and Guidelines The following design codes and standards were complied with for the subsea systems design. The primary design standards are: NORSOK U- 001 ‘Subsea Production System’ DNV OS- F101 ‘Submarine Pipeline Systems’ ISO 13628, Part 1 ‘General requirements and recommendations’ ISO 13628, Part 4 ‘Design and Operation of Subsea Production Systems’ ISO 13628, Part 7 ‘Completion/ Workover Riser Systems’
Standards: ISO 13628 series ISO 10423 ‘Wellhead and Christmas Tree Equipment’ ISO 13623 ‘Pipeline Transportation Systems’ ISO 14313 ‘Pipeline Valves’ ISO 15589- 2 ‘Cathodic Protection of Pipeline Transportation Systems’ ASME B31.4 ‘Pipeline Transportation Systems for Liquid Hydrocarbons’ ASME B31.8 ‘Gas Transmission and Distribution Piping System’ ASME B31.3 ‘Process Piping’ NORSOK Standard J- 003 ‘Marine Operations’ NORSOK Standard M- 001 ‘Material Selection’ NORSOK Standard M- 501 ‘Surface preparation and surface coating’ NORSOK Standard M- 503 ‘Cathodic Protection’ NORSOK Standard M- 601 ‘Welding and inspection of piping’ NORSOK Standard M- 630 ‘Material datasheets for piping’ NORSOK Standard M- 650 ‘Qualification of manufacturers of special materials’ NORSOK Standard M- 710 ‘Qualification of non-metallic sealing materials and manufacturers’ NORSOK Standard N- 001 ‘Structural design’ NORSOK Standard Z- 010 ‘Electrical, instruments and telecommunications’ NORSOK Standard Z- 015 ‘Temporary Equipment’ NORSOK U-009 ‘Life Extension for subsea systems’ NORSOK Y- 002 ‘Life Extension for Transportation Systems’ NORSOK N- 006 ‘Assessment of structural integrity of offshore load bearing structures’ API 5L ‘Specification for Line Pipe’, 42nd Edition, 2000 EN ISO 14723 ‘Subsea Pipeline Valves’
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PED ‘European Pressure Directive’ SAE AS4059 ‘Cleanliness specification for hydraulic fluid’ DNV-OS-C501 ‘Composite Components’
Subsea Recommended Practices: DNV, RP B- 401 ‘Cathodic Protection Design’ DNV RP F- 102 ‘Pipeline Field joint Coatings and Filed repair of line pipe coating’ DNV RP-F- 103 ‘Cathodic protection of submarine pipelines by galvanic anodes’ DNV RP-F- 106 ‘Factory applied external pipeline coatings for corrosion control’ DNV RP-O- 501 ‘Erosive wear in piping systems’ DNV RP- F111 ‘Interference between trawl gear and pipelines’ DNV RP- F112 ‘Design guideline for duplex stainless steel used for subsea equipment exposed to cathodic protection’. DNV RP- F116 ‘Integrity Management of subsea pipeline systems’
9.3
Design Life The existing subsea facilities have a 15 years design life + 5 years design storage time (storage time is time from being pre-commissioned to start-up). The existing equipment was installed in 2008/2009. Since the pipelines and spools were left with a preservation fluid comprising oxygen scavenger and biocides, which in 2012 was analysed by DNV with the conclusion that it still meet thecorrosion preservation requirement/capacity with It only minor deterioration (<10%), internal is considered being negligible. is further considered that eventual oxygen left in the seawater inside the pipeline after installation that might cause corrosion, now has ceased. The subsea facilities, like the pipelines and umbilicals are managed in accordance with Repsol Integrity Management System. Inspection are performed without disturbing the preservation fluid and thus avoiding infiltration of new oxygen. By avoiding internal corrosion and the fact that the systems are duly protected against corrosion to the outer surface by coating or cathodic protection, it is foreseen that any disturbances to its designed life-time will be negligible and about equal to its srcinal design life (15 years) from the production start-up. After start-up of the production, the system will be regularly checked against corrosion, damage and failure by external and internal inspections, which will be a good foundation for the evaluation of an extended lifetime, should this be required later in the production life.
9.4
Location The Yme positions are given in table below using UTM, zone 31, 3° East, International spheroid, Datum European 50. Locations of the Beta and Gamma drill centres are specified inTable 9-2. Data are extracted from Ref 9.31. These are subject to satisfactory survey. The acceptable uncertainty radii around these targets are 50m. Beta North template location is yet to be decided.
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Item
Grid Heading
East
North
239
o
581 454.4
6 402 546.8
Beta Manifold
240
o
581 497.1
6 402 518.5
Gamma Caisson Location - Production and
239.35°
Beta Wellhead Protection Structure – Production and WI
591 222.5
6 409 412.8
WI SLS –Export to Tanker (GBS coordinates)
210.6
592 420.9
o
6 410 133.9
Table 9-2 Facility positions The location for the Yme Storage tank, caisson and topsides facility is at the Gamma drill centre. The srcinal Yme development top-hole locations are presented inTable 9-3. Item
East
Beta
04.21.20E
54.45.15N
North
Gamma
04.31.00E
57.49.20N
Table 9-3 Original Yme Development Top Hole Positions The former Statoil Beta template was located at approx: 6402400 N – 580700 E.
9.5
Subsea Infrastructure Overview The references in section 9.1 give further details. The Yme New Development consist of a production facility with surface wells at Gamma location, and a single Beta subsea step out tied back to the risers at the Yme Production Facility. The Beta location is equipped with two production wells and one water injection well. A 10” production pipeline and a 6” water injection line ties the two locations together. A 4” service line is installed and will be used for annular communication and as a service conduit to the wells via a dedicated header. The main purpose of this line will now be to provide gas lift gas for artificial lift. Chemical injection will be routed to the trees using lines within the umbilical. The produced fluid to, and the water injection from, the Production Facility are transported using rigid risers routed through ‘J’ tubes. Dynamic umbilical and power line are similarly routed. Offshore tanker loading will be performed using a Submerged Loading System (SLS) and an oil export riser and pipeline is installed to route product to the offshore tanker interface.
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Figure 9-1 Yme Subsea Facilities
9.6
Material Selection This is described in references 9.1, 9.6 and 9.4, with further details described in references 9.13 and 9.14. . Future development of the Beta Nord shall comply with the same and supplementary requirements as applicable as per the Regulatory compliance plan (ref Error! Reference source not found.).
9.7
Subsea System Description
9.7.1
General Information A total of three subsea wells at Beta are drilled for the initial development. Further information is found in reference 9.1 In the caisson there is a spare 10” pipe for a future tie -in. For Water Injection, there is a 6” TEE at the base of the subsea storag e tank, allowing the tie-in of a future WI line. Note the WI riser is 8”, but reducing to 6” for the pipeline.
9.7.2
Design Well Flowrates Updated well flowrates are given in Appendix 1. The new flowrates are well within the well design rates, and do not require erosional analysis updates. Current ESP pump design limits flow to around 3500 Sm3/d (22000 bpd).
9.7.3
Well Shut-in Pressures and Maximum Wellhead Flowing Temperature Preliminary closed in tubing Head pressures (CITHP) are presented in section 5.5 and preliminary flowing wellhead temperature profiles are presented in section 0.
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9.7.4
Drilling Interfaces and Workover Facilities See reference 9.1. With the current concept, the Jack Up drilling rig and production unit is integrated. The rig must be able to reach all well slots on Gamma without having to be repositioned on seabed. Simultaneous drilling and production from the same drill centre is required. The drilling rig will be in control of the well it is working on, and the facility will be in control of all other wells. All automated safety functions shall be integrated for the entire installation For a floating concept, the WHP shall be designed to allow access to all wells from a standard North Sea Jack-Up rig.
9.8
Subsea Xmas Tree and Workover System See reference 9.4 for general information. Subsea wells are installed on Beta. Production and injection rates are presented in Appendix 1. The workover system will be sized for depth, usage, pressure regime and testing duties. The system and tooling allow for the running of all tree tooling and equipment and facilitate the control of the tre e system from the driller’s cabin. All units shall comply with temporary unit recommendations of NOROG and possess the ability to meet emergency shutdown needs of a rig. Risers, open water or landing string, shall be designed according to ISO 13628-7.
9.8.1
Tree Design Overview See reference 9.1, 9.15, 9.16, 9.17 and 9.18.
9.8.1.1
Pr oduction Wells Parameter
Maximum Design Pressure
Value
345 bara
Maximum Design Temperature
121°C
Minimum Design Temperature
-46 °C
Table 9-4 Subsea Tree Design Conditions The trees require the facility for gas lift though annulus. Adjustable chokes are required on both production and annulus bores.
9.8.1.2
Water Inj ection Wells Parameter
Maximum Design Pressure
Value
345 bara
Maximum Design Temperature
121°C
Minimum Design Temperature
-46 °C
Table 9-5 Subsea Water Injection Tree Design Conditions Page 71 of 119
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9.9
Subsea Structures The subsea templates, manifolds and riser porches are presented within this section. For details, please refer to references 9.1, 9.2 and 9.3.
9.9.1
Subsea Template Beta The subsea template is the supporting structure and guide for the well conductors and the interface to the manifold flow paths and monitoring points: A multi well slot modularised subsea template with an over-trawlable protection structure to protect the structure and its internals from the detrimental effects of fishing gear impact and dropped objects, The template is the foundation for the PGBs or other such units, manifold system, controls elements and remote connection hubs and accessories, The structure layout is suitable for operations from the jack- up rig “Mærsk Giant” and from a typical semi-submersible rig.
9.9.2
Subsea Template Beta North Final layout of Beta North is not decided, but the most likely solution is a new two slot template located in the vicinity of existing Beta template and tied into this manifold. Further info can be found in ref. 54.
9.9.3
Subsea Production Manifold The production manifold has the following properties; The manifold can be installed / retrieved without removing the Xmas trees.
The arefor equipped with ROV valves. The manifold manifold headers is designed the distribution of operated control fluids and chemicals with necessary ROV operated isolation valves towards each production slot. The manifold has headers for each service. ROV operated valves shall be provided between the header and the wells. Double barrier philosophy is incorporated for start-up or repair operations. It shall be possible to route from the trees to the production or the injection header. The production manifold has spare tie-in points for future connection of Beta North Connections for connecting temporary Pig receivers/ launcher For further information see references 9.19, 9.20, 9.21 and 9.22.
9.10
Flowlines, Risers, Flowline Jumpers and Umbilicals
9.10.1
General
9.10.1.1
Pr oduction Flowlines and R is ers
The flowlines, risers, flowline jumpers (from tree to subsea manifold) and umbilical shall transfer and control the production from Yme accumulations to the processing and export facility at the Production Facility. For details, please refer to references 9.1, 9.2 and 9.3.
The produced fluids from the Beta manifold will be transported via a single 10” production flowline to a riser balcony local to the storage tank and further routed from the riser balcony along the tank through the caisson and onto the Production Facility Page 72 of 119
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9.10.1.2
Water Inj ection Flowlines and R is ers Injection water will be transported from the Production Facilit y via a single 8” water injection riser down the caisson on the storage tank and further routed to the riser balcony. From there water is routed through the manifold on the riser balcony through a 6” pipeline to the Beta accumulation.
9.10.1.3
S ervice Line A stand alone 4” line is installed and routed through the caisson to the riser balcony. From there the service line is routed through the manifold on the riser balcony through a 4” line to the Beta manifold. Thisto permit: gas lift scale squeeze production line depressurisation potential pig driving fluid transmission In the Yme New Development, the primary function will be gas lift.
9.10.1.4
Umbilical The umbilical provide hydraulic fluid for valve operation, chemicals, as well as low voltage power and instrument connections for the subsea template. The chemicals distributed in the umbilical are: Scale Inhibitor (Downhole) Asphaltene Inhibitor (Into Gas lift gas) Methanol (to x-mas tree) Corrosion Inhibitor (Manifold Injection) Wax Inhibitor (Manifold injection
9.10.2
Beta North Flowlines With a new template located in the vicinity of existing template and manifold, the flowlines used for tie-in are likely to be relatively short flexible lines and control umbilical. Protection by means of rock-dumping, trenching and spool covers / tie-in loop covers will be required.
9.10.3
Flow Assurance Production profiles to be utilised for analysis of the production flowlines and risers are presented in Appendix 1. A Flow Assurance Assessment and Plan (reference 35) has been developed. For work related to the existing pipeline, the following U-values apply (relative to OD): 10” Production Pipeline & Spools : 2.91 W/m2K 10” Production Spools, Bends : 2.99 W/m2K
9.10.4
Erosion The Yme New Development will keep flow/ drawdown within the envelope of existing erosion calculations for subsea equipment (manifolds, chokes, and bends), jumpers, flowlines and risers.
9.10.5
Power System The dual electrical submersible pumps (ESPs) are provided with power from a distribution system connected to the Production Facility using a dynamic section to the riser base and a static length from the base to the manifold locations. The ESP’s are not planned to be used for lift on Beta, hence power umbilicalinstalled is available for other services if required. Page 73 of 119
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9.11
Risers Risers are installed for the services that are identified as Beta dedicated in addition to an oil export riser to route product to the oil export pipeline and SLS. In addition, umbilical risers are installed for the Beta controls & chemicals umbilical and Beta ESP power umbilical. Additional provisions for a future subsea tieback have been installed in the caisson on the Gamma location. Additional tie-in points are available on the riser balcony on the storage tank as well as on the Beta Production Manifold.
9.12
Subsea Production Control and Monitoring System The subsea control system shall interface with the process control system located on the Production Facility using acceptable protocols and hardwired to facilitate Yme ESD requirement. The following equipment will need be located on either the MODPU or the WHM Subsea Control Unit, Master Control station, Electrical Power unit, Test panels and modems, Hydraulic power, to be supplied from a dedicated HPU, Umbilical termination and hang-off heads, Junction boxes. The interfacing of systems is the responsibility of the contractor for the new topsides. Herein lay the responsibility for mechanical, electrical and instrument interfaces, as well as ensuring that all topsides equipment required to operate the
subsea systems is available, or procured. For further information, see chapter 9.1 references 9.1, 9.23, 9.24, 9.25, 9.26, 9.27, 9.28 and 9.30.
9.12.1
Production Monitoring For reservoir management purposes, production data must be acquired and transmitted in such a way that measured total produced volumes of oil and water can be allocated to individual wells, average reservoir pressure can be calculated and sand production monitored.
9.13
Subsea Metering No multiphase or other meters are installed subsea. Production will not be directly metered, but component rates and allocation will be deduced from other ESP pump instrumentation where available.
9.14
Leak Detection from Subsea Facilities See chapter 9.1 reference 9.9. There is currently no leak detection system installed neither on the existing Beta Facilities nor on the Submerged Loading System.
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9.15
Sand Detection from Subsea Facilities There are no sand detectors installed on the subsea facilities. Sand detection equipment shall be installed upstream the inlet and test separators (ref 8.4.3).
9.16
Preservation Status of Existing Facilities Proper preservation of existing facilities is of crucial importance with regards to minimising potential degradation effects in the period from installation in 2008 until the facilities are becoming operational. References 9.10, 9.11 and 9.12 must be paid due regard in this aspect and preservation issues must be carefully evaluated regularly. Ref 9.12 concludes on preservation throughout 2012 only and an update of the report is required in due course.
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10
Production Facilities
10.1
Description of Facilities The Production Facility will be either a fixed installation process facility hooked up to a Wellhead module on the Yme caisson, or a floating installation connected with pipelines to a WHP at the Yme caisson. Already installed are a caisson containing wells and surface trees located at the Gamma drilling centre. Existing storage tank can be reused if applicable. One wellhead template has been installed at Beta location, and is tied back with a 12 km pipeline. Existing separate offloading point has been installed (SLS) and can be used for Yme New Development Project if applicable.
10.2
Storage Topsides production facilities shall deliver crude of the following quality to the storage tank and on to the export tanker (reference 18): Item
Design Value
Max Crude Temperature (°C)
60
Min Crude Temperature (°C)
42
True Vapour Pressure (bara)
< 0.95 @ 60°C
Reid Vapour Pressure (bara)
0.56
Base Sediment & Water (%)
<0.5
Note 2
Comment
To avoid wax deposition / failure to flow / excessive heating duty in export tanker To reduce emissions from caisson.
Note 1
For export tanker compatibility, keeping temperature < 50°C. by volume Fresh water dilution is required to meet this -
specification. A target of 100 mg/l Cl is used -
Salt content (mg/l Cl )
<100
to
avoid
oil
price
penalty.
If
cost
is
prohibitive, a target of 200 mg/l may be acceptable subject to company approval Notes
1.
If cooled further than 60°C before entering caisson (down to a minimum of 50°C), a TVP=0.95 bara at this lower temperature can be accepted.
2.
If salt specification is not fulfilled with other means than basic separation, a BS&W of 0.15% is required to meet 200 mg/l mg/l salt content.
Table 10-1 Stabilised Crude Oil Specification
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The Subsea tank have sufficient storage to accommodate Repsol’s desired crude export parcel size plus an extra buffer to provide a margin for adverse weather or tanker scheduling delays. Repsol desires to export 40,000 m3 (250,000 bbl) parcels at standard temperature and pressure. The storage tank system ensure that the space not occupied by crude never contain an explosive mixture of hydrocarbon vapours and air, by storing over seawater. The pump caissons shall be purged with nitrogen. The system has been designed to minimise overboard discharges and atmospheric emissions: Item
Design Value
Comment Target
Water discharged from storage or slops in normal operation
< 10 mg/l
average
PPM
over
month
–
contractor to assess if minor increase in emission can give large cost saving (step change), < 30 mg/l regulatory max. per day N.B. A mixture of VOCs and Inert Gas may
VOCs emitted from storage or slops to atmosphere in normal operation
Negligible
be
emitted
to
atmosphere
if
individual
storage tanks or pipe systems have to be purged for inspection and maintenance.
Table 10-2 Discharge Specification from Storage and Slops
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10.3
Submerged Loading System The off-loading has been sized and configured to deliver the following performance: Item
Design Value
Comment
3
2 x 1250 m /h Export fluid delivery rate to
Pumps - Sufficient to deliver
tanker
maximum size parcel in 16 hours
3
Parcel size is 40,000 m , which allow some buffer capacity within maximum 3
storage capacity of 48,000 m (reference 30). To ensure adequate separation between
Minimum
distance
between
tanker and production unit exports via a
subsea remote loading point (PLEM),
and
any
1350 m
fixed
Production Facility
seabed line to a separate offloading facility. Actual distance between tanker and production facility will vary due to weathervaning during loading operation. Existing hose terminates in a 20” Hose
Hose, hawser, telemetry and
To match standard
End Valve with an adaptor to the 16”
position references fitted to
Norwegian sector
hose. There is a 16” Marine break away
DP fleet
coupling installed on the hose. PLEM
facility.
Position is N 6410131.69; E 592415.75.
Table 10-3 Crude Oil Export system Specifications 10.3.1
Requirements for existing offloading The topsides facility need to supply the offloading hose with up to 10 m3 of fresh water after offloading to avoid collapse due to vacuum/ cooling (reference 34). Testing has identified need for modifications to installed SLS system to meet offloading requirements.
10.3.2
Alternative offloading Existing SLS require extensive modification. Provision of alternative offloading is desired, and an alternative design shall be offered as an option. Alterative offloading shall as far as possible meet the fluid delivery rate to tanker as given in Table 10-3.
10.4
Topsides and Wellhead Module The Yme Process will be adapted to the existing process facilities if relevant. If no existing facilities are in place, Repsol can provide previously proposed designs. The caisson wellhead module operational design weight shall not exceed 800 tonne. The facilities shall provide spare space and equipment loading capacity to allow for future developments. The spare weight capacity shall not be less than 500 tonne. Suitable future deck space area/ location shall be identified by contractor.
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10.4.1
General An offshore production topsides facility is proposed featuring: Production reception / inlet facilities Production separation train and crude oil stabilisation Gas compression to meet lift gas, gas re-injection and fuel gas requirements Gas conditioning Produced water treatment and injection/ disposal Power distribution and integration with existing power generation if relevant Essential utilities (flare, drains, instrument/plant air, nitrogen, seawater, diesel, deluge and foam systems, chemical injection) Process, well control and process shutdown systems, emergency shutdown systems and fire and gas detection systems, Support facilities for stabilised crude oil storage (including heating facilities for fluid in subsea storage tank) – unless other facilities are available Stabilised crude oil off-loading facility for shuttle tanker crude oil export – unless other facilities are available
Production Facility capacity requirements are presented in Table 10-4. Electric submersible pumps have been chosen as the preferred artificial lift mechanism for Gamma East wells, with gas lift as the lift mechanism for the Gamma West and Beta subsea wells. Compressed gas molecular weight variations for different operating cases shall be considered in the compressor design. Existing Beta subsea production well design incorporate both ESPs and gas lift valves, but new subsea wells and recompletion will be gas lift completion only. The service line will be utilised for gas lift supply.
Service
Units
Facility Design Rates
Produced Oil
m3/d
6 500 - 9 000Note 4
Produced Water Treatment
m3/d
12 500Note 5
Gross Produced Liquids
m3/d
17 800Note 5
3
HP Gas Compression, Dehydration and Injection
Sm /d
Gas Lift
Sm3/d
700 000Note 2
m3/d
6500Note 3
Produced Water Injection
3
m /d
13 000Note 5
Est. flowing THP Gamma
barg
13
Inlet Separator Pressure
barg
10
Seawater De-aeration
Note
900 000 – 1 100 000Note 1
3
1. 900 000 Sm /d require two ESP’s in operation. As far as possible the plant shall be designed to achieve 1 100 000 Sm3/d (Full Gas Lift). Page 80 of 119
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2. Only applicable for sizing of gas lift pipework etc. 3. Design to allow for future offshore installation of SW treatment and injection facilities. 4. Given short expected plateau production, the maximum oil capacity can be adjusted with limited economic impact 5. Somewhat lower rates may be acceptable as long as this does not significantly impact oil production (see profiles in chapter 5.2).
Table 10-4 Yme Production Capacities (Stream Days) Although there is no history of H2S on Yme, the process systems materials shall accommodate sour service, and be designed according to ISO 15156 (NACE MR0175).
10.4.2
Well Conductor and Riser Caisson A total of 9 surface well slots have been designed in existing caisson. Details of the well types and designations are presented inTable 10-5 (reference 14). Sufficient space shall be allowed for in piping and manifold design to utilise all slots in future. Well Name
Caisson
Reservoir Structure
Well Type
Slot C1
1
Gamma South East
Oil Producer (ESP)
C2
2
Gamma North West
Oil Producer
C3
3
Gamma North West
Oil Producer
C4
4
Gamma South West
Oil Producer
C5
5
Gamma West
Water and Gas Injector
C6
6
Gamma West
Water and Gas Injector
C7
7
Gamma North East
Future Oil Producer (ESP)
C8
8
Gamma East
Future Water Injector
C9
9
Gamma South West
Future Oil Producer
Table 10-5 Surface wells: Type and designation Identified risers for remote field tie-backs are presented in Table 10-6 (Reference 14). Riser Slot
Riser Diameter
Riser Designation
10
10 inch
Beta Oil Production
11
8 inch
Beta Water Injection (Note 2) Page 81 of 119
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12
10 inch
Future Oil Production (Note 1)
13
4 inch
Beta Service Line
14
16 inch J-Tube
Beta Chemicals and Control Umbilical
15
16 inch J-Tube
ESP Power
16
16 inch J-Tube
Future Chemicals and Control Umbilical (Note 1)
17
16 inch J-Tube
Future Power Cable From Shore Contingency
18
16 inch J-Tube
Future
Notes
1.
The total system to be able to tie in a Beta lookalike
2.
Spare 6” TEE at storage tank base for Future field tie -in to
Water Injection riser slot 11.
Table 10-6 Remote production facilities riser designations 10.4.3
Platform Wells
10.4.3.1
Pr oduction Wells
Parameter Maximum Design Pressure
Value 345 bara
Maximum Design Temperature
121°C
Minimum Design Temperature
-46°C
Table 10-7 Platform Production Tree Design Conditions Adjustable chokes are required on production flowlines.
10.4.3.2
Water/G as Inj ection Wells
Parameter Maximum Design Pressure
Value 345 bara
Maximum Design Temperature
121°C
Minimum Design Temperature
-46°C
Table 10-8 Platform Water/ Gas Injection Tree Design Conditions Adjustable chokes are required on the injection flowlines. Production profiles are given inAppendix 1.
10.4.4
Production Separation Produced fluids from the Gamma platform wells and Beta subsea production flowline will be received at the topsides processing facilities. Inlet production Page 82 of 119
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separators’ operating pressures are anticipated to be around 10 barg. Gamma fluids are anticipated to arrive topsides at temperatures in the range 75 to 100°C over field life. Following gas breakthrough, some Gamma West wells may be choked back, resulting in slugging and intermittent lower temperatures on gas. Beta production fluids are anticipated to arrive at 40 to 65°C over field life for two well production, but below wax appearance temperature (42°C) during gas lift operation of one well. Slugging will give fluctuating inlet temperatures with the lowest temperatures seen at unisulated riser base. Two inlet production separators are proposed, a HP Stage Separator and a Test
Separator sized for the maximum of either a single Gamma well or full Beta production. To achieve maximum rates, both separators canbe operated in parallel. It is required that an inlet heater be provided on the Beta flowline to heat fluid to further facilitate Beta fluids separation (to around 80°C to avoid emulsions; reference 26 and 24). Space, weight and tie-in allowance should allow for a similar future inlet arrangement for similar subsea tieback. Emulsion problems were experienced during the srcinal Yme development. Low Beta fluid arrival temperatures and high shear rates in Gamma fluids would have contributed to these problems. Gamma East production wells will experience high fluid shear through the ESPs. The poor separation in the srcinal development resulted in Yme crude being sold at a considerable value discount, on account of the high water content and salinity. The Yme New Development design shall incorporate adequate crude oil separation facilities to ensure high crude sales value. Interstage heat is included to ensure stabilised crude specifications (TVP/ RVP) can be met. Oil from the 1st stage separator should be diluted with fresh water to ensure salt specification is met. To avoid separation upsets, dirty streams (closed drain, PW reject streams, etc.) should not be recycled to separators if this can be avoided. The oil must be cooled to below 60°C and metered prior to flowing to storage. Export crude quality specification is presented in the following table. Criteria
Units
Specification
Base, Sediment and Water (BS&W)
vol%
< 0.5 Note 2
Reid Vapour Pressure (RVP)
Bara
<= 0.56
Salt Content
mg/l
< 100Note 1
H2S Content
ppm
<3
ContentCO2 Notes
mole%
< 0.1
1. If achieving the target of 100 mg/l proves challenging, meeting 200 mg/l may be acceptable subject to company approval. (Reference 18) 2. Salt content of Yme produced water is 121,000 mg/l Chloride. The necessary BS&W to meet the salt specification (200 mg/l) is 0.15% by volume. If fresh water dilution to remove salt is used, a BS&W of 0.5 vol% is acceptable. 3. The salt content of the product oil is measured to ASTM D3230, which measures chloride (salts) concentration in crude oil. The range of concentration covered by ASTM D3230 is 0 to 500 mg/kg (or 0 to 150 lb/1000 bbl) as chloride concentration/ volume of crude oil. Page 83 of 119
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Table 10-9 Export Crude Oil Specification The topsides production manifold configuration should be designed to permit switching of the Beta field production or individual Gamma wells between the HP and Test separators. Criteria
Units
Design Rate
3
Oil
m /d
Produced Water
m /d
Gross Produced Liquids
m3/d
Gas Handling Note
7000
3
3
Sm /d
Notes 10 barg Arrival Pressure
8500 10 barg Arrival Pressure 13000
10 barg Arrival Pressure
934,000 Including Gas Lift Allowance
1.
Table 10-10 Indicated HP Stage Separator Design Criteria (Stream Days)
Criteria
Units
Oil
m3/d
3500
10 barg Arrival Pressure
3
4000
10 barg Arrival Pressure
4800
10 barg Arrival Pressure
Produced Water
m /d
Gross Produced Liquids
m3/d
Gas Handling
Sm3/d
Design Rate
523,500
Notes
Including Gas Lift Allowance
Table 10-11 Indicated Test Separator Design Criteria (Stream Days) Previous slug analysis suggested 11 m³ slug volume is sufficient in the inlet separators’ design (reference 15). Slug volume has been verified in previous phases, but care should be taken to verify maximum separator/ downstream system drain rates and control system response (reference 40). Significant sand production is not expected, but for design of new equipment, the following parameters shall be used: 25 mg Sand/ Solids production per litre of produced water Average particle size of 20 μm Production separator design shall incorporate nozzles and space allocation for
future sand sparging and removal facilities, should these prove necessary.
10.4.5
Gas Compression and Treatment The GOR of the oil produced is ranging from 61.3 (Gamma) to 54.4 (Beta) Sm³/ Sm³ (Reference 24). Beta North West has a GOR of about 63 Sm³/ Sm³. There will be no gas import / export. Produced gas will be used for fuel gas, compressed and re-injected, or used for lift gas to the Beta subsea production wells. Gas from the inlet separators, operating at around 10 barg, flows to the compressors. Drying of the gas is required to protect 4” beta service line and well annuli from corrosion. The following boundary conditions should be noted: Page 84 of 119
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Gas injection pressure is limited by wellhead design pressures of 345 barg o Design point should be 250 barg @ rated flow at wellhead (see Table 4-3) o Figure 5-9 show that pressure within months is reduced to nearer 200 barg Beta Gas lift o Gas Lift pressure maximum 240 barg at wellhead when unloading o When in normal operation, pressure isreduced to below 200 barg
Fuel Gas pressure will be governed by turbine type – usually around 30 barg For Beta Gas Lift, the Gas Dehydration Performance specification (which pipeline design is based on) is:
Criteria Maximum Water Content
Units
Specification
mg/Sm³
< 40
Table 10-12 Gas Dehydration Specification The last stage of separation and the coalescer operate at low pressure to achieve the required vapour pressure specification for the oil going to storage. The gas from the LP separator will be compressed by a LP compressor, which discharges to the suction of the main compressors.
10.4.6
Produced Water Treatment The bulk of the produced water will be separated from the oil in the inlet separators. The produced water treatment facilities shall be designed to achieve sufficient quality to allow dumping to sea. Target oil in produced water concentration is presented inTable 10-13.
Criteria
Units
Oil in Produced Water (Target)
mg/litre
Oil in Produced Water
mg/litre
Specification < 10 < 30
Note 1
(Maximum for injection) Note
1.
Due to lack of information, the limit chosen is the Maximum legal daily average figure. Statoil experiences indicate that higher OIW levels may be acceptable for the wells.
Table 10-13 Produced Water Treatment Speciofication The produced water facilities should be designed with connections to allow flushing with acid to remove scale.
10.4.7
Water Injection Reservoir pressure (for segments where there are injection wells) will be maintained through produced water re-injection. Allowance for future Seawater treatment facilities are required in event of aquifer performance not as predicted, Page 85 of 119
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or to provide flexibility for future tie-ins. Seawater injection water specification is defined in Table 10-14: Criteria
Units
Filtration Requirements Oxygen Content Note
1.
Specification Pump protection
ppb
< 10Note 1
Requirement is set based on design of existing subsea equipment and wells.
Table 10-14 Seawater Injection Specification There is a risk of barium sulphate scaling when injecting a mixture of sea water and produced water. As far as possible only produced water shall be injected in Beta wells. For Gamma wells, produced water shall be favoured to minimize emissions to sea. Produced water and seawater shall not be mixed topsides prior to injection. Allowance for future Seawater injection routing and manifolds shall be made in accordance with the above restrictions. Significant sand production is not expected, and was not experienced when Yme was produced previously. Filtration for Produced Water is not required other than for injection pump protection. The maximum produced water injection temperature is 60°C, limited by the 8” riser/ 6" water injection line from Gamma to Beta. The produced water discharge to sea do not have a specific temperature restriction, but temperature effect on environmental impact (including risk of exposure to HC gases; benzene, VOC) of PW discharge to sea shall be assessed.
10.4.8
Power Requirements and Fuel Supply Electrical power will be used to drive process, drilling (if available), marine and accommodation equipment. The Production Facility must also provide electrical power to the ESPs. The power generation system need sufficient robustness to supply two (Gamma East wells) ESP’s simultaneously. Expected power requirement is in the order of 15– 20 MW, pending on process. The WHRU’s may supply process heating requirements through a heating medium system. Heat requirement is expected to be in the order of 10– 14 MW, pending on process.
10.4.9
Chemical Injection Chemical injection requirements are presented in section6.12. Chemical injection storage facilities should as far as possible be based on existing facilities, but sizing shall be considered on the following criteria:
Chemicals for continuous use – a minimum storage capacity for 10 days at maximum injection rate, Batch chemical use – storage capacity to be determined based on frequency of batch operation and assuming a 10 day supply boat period. Final capacities will be agreed between contractor and company. A subsea chemical distribution system is provided to distribute chemicals to individual wells (see section9.10.1.4). Monitoring of the flow down each chemical line shall be provided.
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10.4.9.1
S cale Inhi bitor S queeze of Pr oduction Wells The production system shall be configured to enable scale squeeze operations to be carried out intermittently. Scale squeezes will commence once wells start cutting water and may be required up to two times per year per well. Facilities are required to dose individual wells. Typically a scale squeeze operation involves a 24 m³ (150 bbl) preflush, 207 m³ (1300 bbl) treatment and 556 m³ (3500) bbl flush with dosed water at flowrates of approximately 90 m³/h (13 600 bpd). Scale squeezes will be facilitated through the use of drilling equipment. For platform wells, access will be through the x-mas tree (kill wing). For Beta wells, a suitable tie-in point must be facilitated at a service line manifold on the caisson. When squeezing beta wells, gas lift supply to all Beta wells will be impaired.
10.4.9.2
A cid Washes New equipment in the production system shall be configured with sufficient nozzles and valves to enable inhibited acid washes (organic, inorganic or chelant) to be carried out intermittently. For existing equipment adding extra nozzles should be considered.
10.4.10
Measurement The crude oil and gas shall be measured to a standard acceptable to the Norwegian authorities. The following NORSOK standards can be used as guide for measurement and manual sampling facilities for the produced oil, fuel gas and flare gas metering: I-106, Fiscal metering systems for hydrocarbon liquid and gas
NPD Regulations It is desired to measure many streams on the installation. The practicality of introducing this shall be discussed and agreed during FEED.
10.4.10.1 Allocation The operator will perform allocation and reconcile fluid volumes from individual wells (producers and injectors) on a monthly basis from daily figures. Daily figures are either directly monitored and transferred or calculated from 15-minute intervals. As a backup calculation based on well performance (P, T) is required. An online system to collect, calculate, present, transfer data to the operator that will perform the final reporting and reconcile production figures is required. Typical values are: Valve status, Pressure/ Temperature measurements from wells and process, Rates and consumptions.
10.4.10.2 Fi s cal Metering The oil export metering system shall be designed for the maximum continuous offloading rate. The oil export metering system shall be used for custody transfer purposes only. Meters on the oil export system shall use high reliability low maintenance flowmeters of proven technology. A redundant, spare meter shall be included in the metering system to allow removal of the master flowmeter for annualcalibration. Proving shall be conducted in accordance with NPD regulations. Metering to Fiscal standard is also required on streams that contribute to CO 2 and NOX tax, typically Fuel Gas and Flare rates. Page 87 of 119
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10.4.11
Sampling Facilities Sample facilities are required for product streams, wellstreams, produced water, and other environmental purposes. The need for sampling should be identified early. Sampling requirements may be set by regulations, standards, NEA, or by Company. Where regular sampling is required, permanent facilities shall be provided.
10.4.12
Subsea Storage Tank and Caisson Interfaces The existing subsea storage tank will be used for Crude Oil Storage as intended, unless the proposed facility has equal or better storage facilities. If existing tank is utilised, the new topsides facility shall provide adequate facilities for supporting this functionality. This functionality includes the following functions, (complete list to be developed in FEED): Crude Oil Storage o Crude oil to caisson o Power and functionality for 2 x offloading pumps o N2 purge to pump caissons o Heating for maintaining offloading/ storage temperature > 42°C o Support/ integration of level instrumentation into SAS o Vent to safe area Ballast Water o Continuous s kimming function for ballast water ‘nose’ tanks o Power and functionality of 2 x skimming pumps o N2 purge to pump caissons o Monitoring of ballast water quality (OIW)
o o
Alarm to CCR at high OIW levels ‘Hot’ Seawater return to caisson
SLS o o
Oil Export Line Freshwater makeup
The existing SLS will require major modifications. An alternative offloading option shall be proposed as an option.
10.4.13
HVAC Design Temperatures The company propose that the extreme temperatures are not used for HVAC design, but rather a slightly less conservative basis to avoid significant overdesign. Typical North Sea air temperature data for HVAC design: Min: -6°C / 90% Relative Humidity Max: 22°C / 75% Relative Humidity For seawater, the following design values shall be used: Min: 5°C Max: y(°C) = 14 – 0.1 * x (m depth) (Ref: Figure 11-1) When designing HVAC components, any temperature rise across SW pumps and system shall be accounted for.
10.4.14
Allowance for Future tie-ins and options The caisson is designed for tie-in of a second subsea tie-back. In this respect, the following allowances shall be made: Routing for an additional 10” production line from caisson Tie -in and to process plant
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Allowance for Future Inlet Heater for production line (Section 10.4.4) Allowance for future tie-in of support to such a development (Tie in to Service Line/ Umbilical on WHM)
Seawater injection will not be installed, but design shall ensure this is available for future installation by Space allowance for main equipment (deaerator, vacuum package, pipe routings etc.) Ensure implementation of system can be performed in line with
requirements set in this BoD(10.4.7). Future weight allowance of 500 tonne has been specified in section 10.4.
10.5
Design Life The Facility and equipment installed shall be designed for a 15 year design life. The facility shall be capable of meeting all statutory/ regulatory requirements for remaining in the field for the design life, taking normal maintenance and repair into consideration. If cost to achieve the design life requires work that incur excessive cost, this can be reduced subject to agreement with company. The terms used are defined in section14.1.
10.6
Environmental Targets The following environmental design parameters have been chosen. Reasonable endeavours shall be used to further improve environmental performance, and these efforts and their consequences presented. Source
Design
Flaring
To be minimised.
Produced Water Discharge
< 10 mg/l oil in water Minimise discharge by PWRI
Chemical Discharge
Compliance to 0 discharge concept
Power Generation
Lo NOX design
Offloading Emissions
VOC recovery system
Solid Waste
Recycle / disposal onshore
Notes
1.
Note 1
VOC recovery for tanker.
Table 10-15 Environmental Design Parameters
10.7
Operational Availability The design of the facilities should seek to achieve as high availability as possible, without excessive cost. The term Production availability is defined in section 14.2. The criteria have been set based on discussions with typical vendor. The availability will be assessed in FEED, and reasonable endeavours will be taken to improve upon this figure. Page 89 of 119
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Criteria
Availability (%)
Production Availability
95 %
Table 10-16 Production Availability
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11
Metocean Data DNVGL has prepared a document which includes a comprehensive set of metocean criteria and premises which can be used for the design and reassessment of offshore structures, subsea installations and marine operations. The above mentioned DNVGL document does not include updated data for current and temperature. Therefore current temperature data shall be taken from Fugro Oceanor report “ Updated Metocean Criteria for the Yme Platform” (reference 42). Data for marine growth, seismic actions, snow and ice shall be taken form NORSOK N-003.
11.1
Temperature data
11.1.1
Air Temperature (°C) The following temperature data has been abstracted from reference 42.
Table 11-1 Monthly and annual minimum, average, maximum temperature and humidity data 11.1.2
Seawater Temperature The following temperature data has been abstracted from reference 42, which contains further narrative and information on salinity and density. For all depths the extreme minimum temperature can be taken as 5°C. The extreme maximum temperature decreases linearly with depth from 20°C at the surface to 10.0°C at 100 m. The seasonal variation of the monthly mean temperature at two depths is shown below.
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Figure 11-1 Seasonal variation of monthly mean seawater temperature From Reference 42, the following temperature data are obtained: Month
Minimum (°C)
Mean (°C)
Maximum (°C)
January
3.72
6.11
8.97
February March
3.16 2.91
5.06 4.85
7.39 7.09
April
3.91
6.09
9.29
May
5.31
9.03
13.05
June
8.20
11.83
16.07
July
10.43
14.61
20.70
Augusts
12.15
15.66
20.23
September
11.28
13.46
16.96
October
8.35
11.68
15.22
November
7.02
9.72
13.08
December
4.02
7.68
10.15
Overall
2.91
9.61
20.70
Table 11-2 Statistics of Seawater monthly minimum, mean and maximum temperature at Surface
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12
Summary of Geotechnical Conditions See reference 10 for detailed Geotechnical design report. Soil Unit No. Depth Interval (m) Soil Description 1 0.0 2.5 – SAND, dense to very dense, fine to medium, with occasional shell fragments 2 2.5 –10.0 SILT, sandy, clayey with thin layers of hard clay and silty sand
3
10.0 –16.0
4
16.026.0 –
CLAY, sand stiff to hard, interbedded with silty fine CLAY, stiff to hard, with pockets and laminations of silty fine sand
Table 12-1 Four-layer deposit at the YME Gamma location (recommended in NGI, 2007) Reference 5 presents Soils parameters for design and Geotechnical data for block 9/2, derived in 2007. Further information and data can be found in references 47 and 48.
12.1
Bathymetric data The water depth at Yme varies around 75 to 100 metres (MSL). The water depth and further data is given in the metocean report (reference 4 and 44). Locations of the drill centres are given in tableTable 9-2, with the exception of Beta North, as this is yet to be determined.
12.2
Yme Beta development site For geotechnical data for the gamma to beta pipeline route, see reference 19 Exact Beta North location not yet identified, and need for additional survey for flowline/ template will be assessed later.
12.3
Flowline/ umbilical route For geotechnical data, see reference 19. Seabed sediments along the route are slightly shelly, slightly silty sand with some boulders and trench infill crossing the route.
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12.4
Production facility site There is only limited information for part of the area, see reference 19. Previously drilling jack up rigs has been placed in the area and there may be spud can depressions in the sea bed.
12.5
Subsidence Subsidence is not expected at Yme. The Yme reservoirs consist of strongly consolidated sandstone that should not collapse. None of the srcinal Yme wells collapsed after five years of production, even if the reservoirs were depleted by approximately 200 bars at the end of the first production period in 2001.
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13
Yme Storage Tank and Caisson The Yme New Development project is based on keeping the existing storage tank and caisson to keep the value of the existing Gamma Wells. Below follow references to the installed system, as well as requirements directly related to this. Facility requirements are set out in section 10.2.
13.1
Existing caisson structure
13.1.1
Caisson support system and document references
Ref 13.1 13.2 13.3 13.4 13.5 13.6 13.7 13.8
A 5.25 m diameter steel caisson cantilevers up from the subsea tank and supports a 10m square cellar deck at 118.9 m above tank base. For drawings see reference 20 and 21
The caisson is supported by the storage tank by a grouted connection at the lower end and by a bracing system connected to the support columns on top of the storage tank. The structural analysis anddesign of the caisson and storage tank was srcinally done by SBM as documented in the following structural design reports: Doc no Description YME-11208-N-3342/P 11208-6042, Structural analysis caisson to tank Rev. 0 connection YME-11208-N-3054/P 11208-6012, Fatigue strength assessment substructure Rev. A
YME-11208-N-3234/P 11208-5852, Rev. 0 YME-11208-N-3586-001/P 112085851, Rev. 0 YME-11208-N-3053/P 11208-5784, Rev. B YME-11208-N-3425-001/P 112085668, Rev. A YME-11208-N-3585-001/P 112085667, Rev. B YME02-23484-N-RA-0008, Rev.01
Local structural analysis substructure MOPUStor Structural analysis column, caisson lower end and bracing Fatigue strength assessment of legs and caisson Structural analysis substructure tank Scantling analysis substructure Caisson Global Analysis
Table 13-1 Storage Tank and Caisson reference documents
13.1.2
Caisson Structure verification
Company has together with our Structural Integrity Contractor performed structural reanalysis to verify the fatigue life of critical parts of the caisson and the caisson supports based on the fatigue damage accumulated from actual loading conditions induced from all relevant historic design conditions. The structural fatigue assessments performed by the Structural Integrity Contractor has identified hot spot areas which has been concluded with lower fatigue life than the required design. These areas have been subjected to detailed NDT inspections, fracture mechanics and probability assessment in order to demonstrate a sufficient safety level. The on-going comprehensive
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structural integrity regime will be maintained for the remaining service life including the removal phase.
13.1.3
Caisson Support Requirements In order to be able to support the new WHM onto the existing caisson and demonstrate that the structural integrity for the existing caisson and caisson brace can be obtained for the remaining service life at the Yme field, then it is required to install a new Caisson Permanent Support (CPS). (Ref52)
13.1.4
Cathodic protection system
13.1.5
Structural Foundation for new Wellhead Module
The cathodic protection system for the Caisson and Storage tank was designed for a service life of 15 years. The Caisson and Storage Tank has been on the YME field since autumn 2008 with both internal and external seawater exposure. The cathodic protection system will therefore have to be reassessed to ensure the required extended service life. To satisfy the requirement of an extended service life of the caisson and storage tank the cathodic protection system shall if necessary be upgraded to meet the design life defined in chapter10.4.14.
In order to be able to support the new WHM onto the existing caisson, the caisson topside will need to be prepared by removing existing structures and equipment. In addition, necessary structural foundation for the WHM will need to be installed. (Ref 53).
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14
Definitions
14.1
Lifetime For the Yme Project, the definition of Lifetime adopted is the same as defined in NORSOK Y-002. The following terms will be used: Design Life Integrity Life Service Life
14.1.1
Design Life Specified period for which the integrity of the system is documented in the srcinal design with anticipated maintenance, but without requiring substantial repair.
14.1.2
Integrity Life Period during which the system or component may be operated without infringing the integrity acceptance level The integrity life is longer than the design life, and in most cases the integrity life cannot be documented. The integrity life is the upper theoretical limit for the design life. Conservatism in design and material data is the background for much of the difference between integrity life and design life. In the design process the focus is on documenting acceptable integrity level for theparameters specified design life. The design process isan often conservative when choosing for calculations and qualifications.
14.1.3
Service Life Time length the system is intended to operate. The service life is a part of the application toward authorities. EXAMPLE: The design life of a system is 25 years. However, the system was intended to operate 15 years (limited by the reservoir predictions), and the operator applied for a 15 years permission. Later the operator wants to extend the service life with 5 years, for a total of 20 years. In this case the design supports the application for service life extension with respect to design life.
14.2
Production Availability The definitions used herein are based on definitions and descriptions in ISO 20815:2010.
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Figure 14-1 Illustration of availability relationships and terminology used. 14.2.1
Availability Ability of an item to be in a state to perform a required function under given conditions at a given instant of time, or in average over a given time interval, assuming that the required external resources are provided. Overall availability for an installation can be expressed as Aoverall = Awells * Aproduction * A export * Aturnaround The different components are treated differently, and are described in the chapters below.
14.2.2
Wells Availability The availability of wells is the time the well is available to produce to its full reservoir potential. Failure of ESP pump, tree-valves, gas lift valves, DHSV testing etc. will impact the individual well availability. In subsurface modelling, values for availability used is 94% for ESP operated wells, and 97% for gas lifted wells.
14.2.3
Production Availability Production availability (Aproduction) is the ratio of production to planned production, or any other reference level, over a specified period of time. The measure is used in connection with analysis of delimited systems without compensating elements such as substitution from other producers and downstream buffer storage. Battery limits need to be defined in each case. The Production Availability in this Basis of Design is based on volume. The reservoir/ well production potential– or plant design capacity - is assumed to be 100% capacity; whichever is the lowest.
14.2.3.1
B attery Li mits In this Basis of Design document, the definition of Production Availability includes: Topsides production facilities Subsea production facilities (including flow assurance, supply of utilities to x-mas trees and subsea facilities)
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Process and Utilities Export facilities Environmental targets Product quality Specifications Water injection (overcapacity may compensate for downtime) One day yearly stop for testing of critical valves To aid clarity for facilities design, the following shall not be included: Wells and reservoir performance Weather restrictions related to logistics (helicopter flights, supply boats and tanker availability) Planned long term maintenance shutdowns (turnaround) and modification projects
14.2.4
Export Availability With export availability, it is the weather criteria that have been considered for the shuttle-tanker. It is assumed the contract with the shipping company is sufficient to ensure tanker availability do not impact this figure. The weather criteria for the tank boats (assuming same class boats as for last contract): Significant wave height (Hs) less than 3.5 m when hooking up to the buoy Hs < 4.5 m for the operation Wind speeds < 20 knots if wind direction could blow the tanker towards the Yme installation An export availability of Aexport > 99.5% is achievable, but require ordering export tanker early when weather is inclement when oil production is above about 4000
Sm3/d (25000 bbld).
14.2.5
Turnaround (Shutdown) Availability Aturnaround is set to 2 weeks every 3rd year. For the relevant year this equals (36514)/365 = 96,2%.
14.3
Vapour Pressures (RVP/ TVP)
14.3.1
Reid Vapour Pressure (RVP) Is the absolute vapour pressure exerted by a liquid at 100°F (37.8°C) as determined by the test method ASTM D-323.
14.3.2
True Vapour Pressure (TVP) Is the equilibrium partial pressure exerted by a volatile organic liquid as a function of temperature. A corresponding temperature is required for TVP to be defined.
14.4
HSE Plan The Health, Safety and Environment (HSE) Plan is document that specifies the main requirements and activities to be developed during the different phases of the project. This document describes how HSE shall be managed by Repsol Norge AS (RNAS) Yme New Development Project organization throughout the project. The project will be conducted in several phases, and the HSE Plan will be updated accordingly. The main objectives of the HSE Plan are to: Present the key HSE requirements to all involved parties/levels
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Provide a vehicle for HSE Management within all levels and phases of the project An HSE Activity Plan which further details the HSE activities will be developed (reference 43).
14.5
Zero environmentally harmful discharge concept Norway’s goal of zero environmentally harmful discharges to the sea was introduced in (White Paper) Report no 58 (1996-97) to the Parlament (Stortinget)
on environmental policy for sustainable development. It has since then been included in several more White papers, and information and current status can be found at Norwegian Climate and pollution agency web-pages. This objective is often misunderstood. It calls for discharges of environmentally harmful substances to be reduced and minimised, not eliminated completely. The zero discharge goal is to be reached within acceptable limits for the environment, safety and economics. This has been underlined by several subsequent reports to the Parlament.
14.5.1
Use of Chemicals This objective involves the following restrictions on chemical usage: no discharges of toxic or environmentally harmful chemicals no discharges of other chemicals which could cause environmental harm no or minimal discharges of substances which rank as pollutants in chemicals. None of the substances in the red and black categories defined by the Norwegian Environment Agency (NEA) may be released to the sea. NEA states in the report that the goal of zero environmentally harmful discharges is regarded as having been attained for chemical additives.
14.5.2
Produced water The following restrictions are also imposed on discharges of hydrocarbons and other natural substances produced together with oil and gas: no or minimal discharges of environmental toxins no discharges of other substances which could cause environmental harm. The greatest remaining challenge is a further reduction in discharges of oil and naturally occurring environmental toxins in produced water. The following guidelines have been given by NEA in 2010 (Reference22): There is no general requirement for produced water (re-)injection For new field developments, overall cost/ benefit evaluations should be carried out; including overall environmental impact of measures to reduce Produced Water emissions (recognising that injection may increase emissions to air, etc.) Long term impact of discharge of produced water to the marine environment is not fully understood. In the coming years there will be a continued focus on reducing these emissions by o Improving effect of existing cleaning technology o Develop new methods for removing harmful substances from produced water Additional requirements in regulations or field specific permits will be considered to further reduce emissions
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14.6
Stream Day vs. Calendar Day rates When presenting production profiles, calculating economy, and designing equipment, production volumes are given per day.
14.6.1
Stream Day Stream day is the maximum production (throughput) the well/ field/ plant can achieve in 24 hours of operation if everything is on line and working. Stream Day is used for designing equipment and to identify production potential. Unless otherwise stated, all presented production profiles and figures in this document are given in Stream Days.
14.6.2
Calendar Day Calendar day is the production for a full year, divided by the days in that year. Baked into the Calendar day figure is Production Availability, Well availability, planned maintenance stops, etc. Calendar day is a lower figure than Stream day. Calendar Day is used typically for calculating project economics, production forecasts etc.
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15
References 1. Zhang, Y. & Hellings, G.; “Yme Well Scale Review”, Helix-RDS, Project No.: PAL0115, Final Report, Revision 000, 26th May 2005. 2. Oilphase; 9/2-7S (9/2-B-3H), “PVT Report; Bottom Hole Samples”, Report No. STAT798, 28/10/1999. 3. Mator; “Particle analysis on Yme produced water and sea water”, Final report, revision 00, 13/02/98. 4. Statoil Report; "Environmental Design Basis Block 9/2 Conceptual Phase", Doc No INGA-NOG-93034, dated 07/06/93.(See also reference 21) 5. NGI; “Talisman Energy – Yme Gamma Soil Investigation Phase 3. Soil Parameter Report”, 20071219-3 December 2007. 6. Statoil report; “Yme Hydrat Manual”, Paladin ObjectID: 17644. 7. Statoil report; “Material Evaluation of Yme Wells”, Paladin ObjectID: 17618. 8. PROLAB; “Well 9/2-1 DST 3, “TBP Distillation, Wax and Hydrocarbon Analysis”, PROLAB report no. 87.53, 19/06/1987” 9. Fugro Oceanor; “Metocean Conditions for Yme” YME-TEN-Z-0001, Revision R4 10. NGI Report; “GBS Foundation Yme MOPUstor” 20061682-2 11. Statoil; “Crude Oil Assay.pdf “ YME3KV97 12. Talisman Energy; “PVT Input for HYSYS Simulation on Yme” YME-TENP-0036 Rev.01 13. DewPoint AS; “Yme HYSYS EOS and Compositional Input”YME-TEN-P0037 Rev.02 14. GustoMSC; “Substructure Caisson Internal Layout Arrangement Plan” YME-11208-N-3202-001 Rev.Z2 15. Scandpower; ”Yme Beta Production Line Transient Analysis Phase 1” YME-300492-P-0030 16. Talisman Energy; PJT-REP-YME-011 “Yme Redevelopment Project – Basis of Design” Revision 02, 15/11/2006 17. Fugro C50871/6813/RO; “YME Field Metocean measurements” YME TEN-Z-0108 Rev. B 18. Repsol; “Crude Oil Specification YME New Development” YND04-REN-ZRA-0002 19. Talisman Energy; “Floyd & Associates Ltd for Talisman Energy NORGE AS Gamma to Beta Pipeline route Survey Report NCS 9/2” YME-TEN-Z0002 Rev A 20. GustoMSC; ”Substructure Caisson Construction Plan” YME-11208-N3098-001 Rev06 21. GustoMSC; “Substructure Caisson Cellar Deck Construction Plan” YME 11208-N-3098-001 Rev06 22. KLIF; ”Nullutslipp fra Petroleumsvirksomheten offshore” Klif memo 190410 23. Oil Plus Ltd.; "Review of reservoir souring potential in the Yme field offshore Norway" 611A-REP-01Rev1 24. Statoil; “Evaluering av de emulsjonsdannende egenskapene til formasjonsvann og fraktureringsæske med olje fra Yme Beta Øst (brønn 9/2-1H).” 25. Statoil “MOM- Emulsion Problems Yme Oil” F&U-UoD/96032 19/11/97 26. Statoil; “Yme 2001 Petroleum Engineering Experience Report Vol1 -3” 01/3286-1 Page 102 of 119
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27. Deleted 28. DewPoint AS; “PVT characterization of the Yme Reservoir Fluids” July 2008 (Stored in CIMAGE) 29. Talisman Energy; “Flow Assurance: Yme Beta – Gamma Pipeline comparison of HYSYS and Subsurface simulation preliminary results” YME01-TEN-P-RA-0002 Rev. 02 30. GustoMSC; “Volume 6 MOPUStor Crude Oil Storage & SLS Exp ort Operations Manual” YME-11208-Z-1050 Rev A 31. Deleted 32. N/A 33. Talisman Energy; “Yme Future – Evaluation of Wax Properties” YME01 TEN-Z-RA-0031 34. GustoMSC; “MOPUStor SLS Pressure Drop, Surge & Heat Loss Calculation YME-11208-Z-1004 rev03 35. Repsol; “Flow Assurance Assessment and Plan” YME04-REN-P-TA-0001 36. Baker Hughes; “VSD Recommendations for Yme” YME01-13948-E-RA0001 37. Deleted 38. Xodus; “Yme Future Flow Assurance for Beta Pipelines” YME01-27338-PRA-0001 39. Deleted 40. Xodus; “Yme Future Flow Assurance – Impact on slugging by using Gas Lift on Beta” YME01-27338-P-RA-0004” 41. Talisman; “Well Design Summary” YME01-TEN-D-RA-0003 42. Fugro; “Updated Metocean Criteria for the Yme Platform” YME01 -25961N-RA-0001 43. Repsol; “HSE Plan” YME04-REN-S-TA-0002 44. DNV GL; “Yme Metocean Data – Metocean design basis for wind, waves and water level” YME04-19259-N-RA-0001 45. Repsol; “Basis of Design Drilling and Completion” YME04-REN-D-FD0001 46. KANFA; “Phoenix Intermediate Phase Technical Report, Appendix G Flow Assurance Study” (Genesis) 40157-KA-00-Z-RA-00001 47. NGI; “Talisman Energy - Yme Gamma Soil Investigation. Laboratory Testing. Phase 2. Factual Report.” 20071219-2 48. Fugro; “Geotechnical Report. Laboratory and In-Situ Data. Gamma site investigation. Block 9/2, Norwegian Sector, North Sea” 71507-5 (02) 49. Repsol, Yme: Subsurface input to Basis of Design optimization, January 2017, YME04-REN-X-RA-0003 50. Repsol; “Scale Review” Yme04-REN-X-CA-0005 51. Repsol; “Chemical treatment of production wells” YME04 -REN-D-RA0006 52. Repsol; “CPS Basis of Design (Design Premise)” YME04 -11624-N-FD53. 0001 Repsol; “WHM Design Premise” YME04-11624-N-RA-0033 54. Repsol; “Preliminary Subsea Basis of Design” YME04 -25647-Y-RA-0001
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Appendix 1 – Production Profiles The production profiles below are developed from work done in late 2016/ early 2017 (ref 49). The case shown is a full gas lift case with a total Gas Capacity of 1,1 mSm3/d. For the rates in the tables to exactly match the 1,1 mSm 3/d capacity, the numbers supplied should be multiplied with well uptime (0.97), as the displayed rates are streamday rates without any uptime considerations. . If the Gamma East wells are being produced by ESP’s, the oil rates will be marginally higher, gas rates lower (as lift gas will not be included), whilst the water rates are likely to increase due to the pumps being able to lift water more efficiently in late life. The higher water rates have been accounted for in the capacities requested for the plant (Table 4-3), and are displayed in the figures in section 4.4. The following profiles are included in this appendix:
Table 15-1 Yme Field total Rates Table 15-2 Gamma Field Total Rates Table 15-3 Beta Field Total Rates Table 15-4 Gamma C1 Producer Table 15-5 Gamma C2 Producer Table 15-6 Gamma C3 Producer Table 15-7 Gamma C4 Producer Table 15-8 Gamma C7 Producer Table 15-9 Gamma C9 Producer Table 15-10 Gamma WAG and Water Injector Well Profiles Table 15-11 Beta D-1H Producer Table 15-12 Beta D-2H Producer Table 15-13 Beta North Producer Table 15-14 Beta East and Beta North Water Injectors
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Table 15-1 Yme Field total Rates Date 15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020
Oil sm3/d 8 846 8 846 8 846 8 553 8 834 8 400
Gas sm3/d 541 472 543 915 535 672 527 241 552 684 538 107
Water sm3/d 1 955 1 946 2 215 2 949 3 289 3 748
15.03.2020 15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023
7 465 6 532 5 966 5 558 7 061 6 610 6 391 6 127 5 726 5 336 4 934 3 941 4 129 3 935 3 637 3 301 3 079 2 808 2 748 2 550 2 343 2 027
488 397 482 916 473 608 467 952 593 385 579 272 594 993 583 563 545 582 565 274 557 478 572 452 569 899 559 427 573 666 566 841 560 732 569 146 561 743 569 286 566 763 566 339
4 075 4 064 3 932 3 970 3 788 4 089 4 652 5 210 5 486 5 455 5 081 5 208 5 291 5 684 5 234 5 619 6 010 6 056 6 489 6 291 6 944 6 731
15.07.2023 15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028
1 996 1 803 1 683 1 590 1 631 1 602 1 451 1 360 1 414 1 382 1 290 1 214 1 259 1 248 1 155 1 094 1 102 1 126 1 045 960 981 1 010
562 311 566 006 564 093 569 543 568 315 569 221 568 240 567 336 566 471 522 033 566 671 532 243 566 745 495 616 513 825 471 313 501 676 436 913 463 681 414 398 418 531 395 892
15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
936 847 878 906 859 804 740 700 673 604 618 595 539 545
403 465 360 657 313 641 343 771 342 966 333 347 367 348 357 846 324 730 288 442 265 617 234 412 185 623 150 084
Yme Totals GL Beta+East sm3/d 240 000 240 000 240 000 240 000 396 785 406 735
GL East sm3/d 100 000 100 000 200 000 200 000 184 551 189 179
Water Inj sm3/d 1 672 1 649 1 692 1 743 1 847 2 011
Gas Inj sm3/d 468 502 471 561 463 620 471 019 481 693 490 064
430 000 430 000 360 000 360 000 347 551 356 624 346 518 375 709 401 633 388 192 360 000 290 000 385 035 392 183 382 464 360 000 360 000 385 549 390 602 360 000 371 652 393 010
200 000 200 000 200 000 200 000 193 084 198 125 192 510 174 749 186 806 180 555 200 000 200 000 179 086 182 411 177 890 200 000 200 000 179 325 181 675 200 000 195 606 174 671
4 014 4 007 3 876 3 913 3 729 4 028 4 572 5 122 5 395 5 368 5 001 5 125 5 215 5 606 5 161 5 540 5 925 5 971 6 401 6 203 6 684 6 383
477 320 494 845 494 845 494 845 494 845 494 845 494 845 494 845 466 810 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845
7 164 7 047 7 435 7 253 7 711 7 953 7 966 7 749 8 160 8 246 8 461 8 053 8 577 8 486 8 527 8 201 8 701 8 660 8 619 8 361 8 791 8 831
395 799 310 000 375 080 392 118 392 971 371 706 393 023 393 651 394 252 385 000 394 113 418 029 394 062 443 472 430 823 455 000 439 262 455 000 455 000 455 000 455 000 455 000
175 911 200 000 194 847 172 359 172 735 193 094 172 757 173 034 173 298 200 000 173 237 183 749 173 214 194 933 189 373 200 000 193 082 200 000 200 000 200 000 200 000 200 000
6 713 6 573 6 804 6 670 7 041 7 225 7 159 6 967 7 307 7 439 7 485 7 225 7 588 7 646 7 608 7 423 7 750 7 853 7 749 7 602 7 922 8 004
494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 449 135 494 845 459 663 494 845 423 052 441 777 398 769 429 696 364 547 391 759 342 136 346 701 323 707
8 697 8 545 8 747 8 956 8 822 8 670 6 811 6 736 6 748 5 781 6 710 6 670 5 621 6 452
455 000 455 000 455 000 455 000 455 000 455 000 372 500 372 500 372 500 302 500 372 500 372 500 302 500 372 500
200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000
7 877 7 792 8 034 8 149 8 087 7 961 6 068 5 991 6 026 5 358 6 024 6 022 5 355 5 993
331 600 288 443 241 714 265 342 264 893 255 591 294 107 285 441 252 756 216 829 194 290 163 333 114 757 79 417
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Table 15-2 Gamma Field Total Rates Date
Gamma Field Total GL West GL East sm3/d sm3/d 210 000 100 000 210 000 100 000 210 000 200 000 210 000 200 000 258 372 184 551 264 851 189 179
15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020
Oil sm3/d 5 898 5 898 5 898 5 898 5 898 5 898
Gas sm3/d 383 966 387 025 379 083 386 485 397 155 405 528
Water sm3/d 1 926 1 909 2 154 2 860 3 124 3 463
Water Inj sm3/d 1 642 1 612 1 631 1 655 1 681 1 725
Gas Inj sm3/d 468 502 471 561 463 620 471 019 481 693 490 064
15.03.2020 15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023
5 664 5 167 4 777 4 476 4 113 3 878 3 885 3 800 3 555 3 296 3 018 2 236 2 466 2 442 2 302 2 075 1 951 1 822 1 881 1 739 1 569 1 347
392 791 410 310 410 294 410 310 410 309 410 309 440 549 440 525 412 490 440 525 440 525 468 599 468 599 468 592 492 664 492 664 492 664 509 974 509 974 520 967 520 969 526 213
3 556 3 305 3 061 3 025 3 133 3 284 3 745 4 219 4 422 4 328 3 897 3 916 3 808 4 112 3 579 3 898 4 228 4 179 4 530 4 286 4 849 4 579
280 000 280 000 210 000 210 000 202 738 208 031 202 135 244 648 261 528 252 776 210 000 140 000 188 041 191 531 186 785 140 000 140 000 188 292 190 759 140 000 136 924 183 405
200 000 200 000 200 000 200 000 193 084 198 125 192 510 174 749 186 806 180 555 200 000 200 000 179 086 182 411 177 890 200 000 200 000 179 325 181 675 200 000 195 606 174 671
3 495 3 247 3 005 2 968 3 074 3 223 3 664 4 131 4 331 4 240 3 817 3 833 3 732 4 034 3 507 3 819 4 143 4 094 4 443 4 199 4 589 4 232
477 320 494 845 494 845 494 845 494 845 494 845 494 845 494 845 466 810 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845
15.07.2023 15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028
1 382 1 232 1 143 1 075 1 137 1 126 992 916 984 966 886 822 878 878 795 743 761 793 720 642 670 705
526 197 532 537 532 535 539 479 539 481 541 476 541 477 541 470 541 469 497 793 543 144 509 387 544 567 474 038 492 825 450 852 481 770 417 512 444 744 395 883 400 434 378 154
4 961 4 791 5 123 4 894 5 310 5 512 5 485 5 228 5 599 5 648 5 823 5 372 5 852 5 719 5 718 5 352 5 810 5 730 5 651 5 356 5 747 5 752
184 706 70 000 136 393 180 977 181 371 135 166 181 395 181 685 181 963 140 000 181 898 192 936 181 875 204 679 198 841 210 000 202 736 210 000 210 000 210 000 210 000 210 000
175 911 200 000 194 847 172 359 172 735 193 094 172 757 173 034 173 298 200 000 173 237 183 749 173 214 194 933 189 373 200 000 193 082 200 000 200 000 200 000 200 000 200 000
4 510 4 317 4 492 4 312 4 640 4 783 4 677 4 446 4 746 4 840 4 847 4 544 4 862 4 878 4 800 4 574 4 860 4 923 4 781 4 597 4 879 4 925
494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 494 845 449 135 494 845 459 663 494 845 423 052 441 777 398 769 429 696 364 547 391 759 342 136 346 701 323 707
15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
636 552 589 621 581 533 529 505 485 423 443 424 372 381
386 049 343 531 296 799 327 197 326 749 317 443 355 967 347 297 314 613 278 684 256 146 225 189 176 612 141 272
5 584 5 399 5 566 5 741 5 581 5 358 5 336 5 325 5 355 4 395 5 326 5 289 4 240 5 073
210 000 210 000 210 000 210 000 210 000 210 000 210 000 210 000 210 000 140 000 210 000 210 000 140 000 210 000
200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000 200 000
4 764 4 645 4 852 4 933 4 846 4 649 4 593 4 579 4 634 3 972 4 641 4 641 3 975 4 613
331 600 288 443 241 714 265 342 264 893 255 591 294 107 285 441 252 756 216 829 194 290 163 333 114 757 79 417
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Table 15-3 Beta Field Total Rates Date
Beta Field Total Water Gas Lift sm3/d sm3/d 30 30 000 37 30 000 61 30 000 89 30 000 166 138 414 286 141 884
15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020
Oil sm3/d 2 948 2 948 2 948 2 655 2 936 2 502
Gas sm3/d 157 506 156 890 156 589 140 756 155 529 132 578
Water Inj sm3/d 30 37 61 89 166 286
15.03.2020 15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023
1 801 1 365 1 189 1 082 2 948 2 732 2 505 2 327 2 171 2 040 1 916 1 704 1 663 1 493 1 335 1 226 1 128 985 868 811 774 679
95 606 72 606 63 314 57 642 183 076 168 963 154 444 143 037 133 091 124 749 116 953 103 853 101 300 90 835 81 002 74 177 68 068 59 172 51 769 48 319 45 794 40 127
519 760 871 945 655 806 907 991 1 064 1 127 1 184 1 292 1 484 1 572 1 655 1 721 1 782 1 877 1 959 2 004 2 095 2 151
150 000 150 000 150 000 150 000 144 813 148 593 144 382 131 061 140 105 135 416 150 000 150 000 196 995 200 652 195 679 220 000 220 000 197 258 199 843 220 000 234 727 209 605
519 760 871 945 655 806 907 991 1 064 1 127 1 184 1 292 1 484 1 572 1 655 1 721 1 782 1 877 1 959 2 004 2 095 2 151
15.07.2023 15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028
614 571 540 515 494 476 459 444 429 416 404 392 381 370 360 351 342 333 325 318 311 305
36 114 33 469 31 558 30 064 28 834 27 745 26 764 25 865 25 001 24 241 23 527 22 856 22 178 21 578 21 000 20 461 19 906 19 401 18 937 18 515 18 098 17 738
2 203 2 256 2 312 2 358 2 401 2 442 2 482 2 521 2 561 2 599 2 639 2 681 2 726 2 768 2 809 2 849 2 891 2 930 2 968 3 005 3 044 3 079
211 093 240 000 238 687 211 140 211 600 236 540 211 628 211 966 212 290 245 000 212 215 225 093 212 187 238 793 231 982 245 000 236 526 245 000 245 000 245 000 245 000 245 000
2 203 2 256 2 312 2 358 2 401 2 442 2 482 2 521 2 561 2 599 2 639 2 681 2 726 2 768 2 809 2 849 2 891 2 930 2 968 3 005 3 044 3 079
15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
300 295 290 285 278 271 211 195 187 181 176 171 167 163
17 415 17 126 16 843 16 574 16 218 15 903 11 381 10 549 10 117 9 758 9 471 9 223 9 010 8 812
3 113 3 147 3 182 3 215 3 241 3 312 1 475 1 412 1 393 1 386 1 383 1 381 1 380 1 379
245 000 245 000 245 000 245 000 245 000 245 000 162 500 162 500 162 500 162 500 162 500 162 500 162 500 162 500
3 113 3 147 3 182 3 215 3 241 3 312 1 475 1 412 1 393 1 386 1 383 1 381 1 380 1 379
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Table 15-4 Gamma C1 Producer Date
Gamma East C1 Producer PW Gas Lift sm3/d sm3/d 355 100 000 470 100 000 397 100 000 498 100 000 501 92 276 689 94 590
15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020
Oil sm3/d 1 214 1 250 999 1 214 1 169 1 560
Gas sm3/d 93 272 96 131 76 833 93 397 89 941 119 945
THP bar 88 74 78 67 63 42
BHP bar 314 301 297 288 282 268
15.03.2020 15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023
2 012 1 921 1 816 1 654 1 396 1 220 1 119 1 038 976 914 844 729 644 582 539 505 477 448 428 410 399 387
154 751 147 669 139 557 127 050 107 241 93 721 85 913 79 670 74 915 70 172 64 786 55 923 49 449 44 696 41 345 38 752 36 632 34 405 32 883 31 502 30 631 29 749
837 787 773 789 856 906 939 983 1 026 1 067 1 099 1 146 1 184 1 218 1 253 1 275 1 308 1 355 1 392 1 426 1 462 1 485
100 000 100 000 100 000 100 000 96 542 99 062 96 255 87 374 93 403 90 277 100 000 100 000 89 543 91 205 88 945 100 000 100 000 89 663 90 838 100 000 97 803 87 336
14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14
249 243 238 235 231 230 229 230 232 233 234 235 237 238 240 242 244 247 249 251 253 255
15.07.2023 15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028
373 361 351 341 330 316 303 286 277 271 266 261 256 251 244 237 229 222 214 203 191 177
28 626 27 724 26 925 26 166 25 327 24 256 23 290 22 002 21 286 20 851 20 431 20 030 19 662 19 247 18 751 18 171 17 580 17 056 16 420 15 614 14 693 13 606
1 496 1 513 1 530 1 548 1 565 1 580 1 595 1 606 1 617 1 626 1 634 1 641 1 648 1 655 1 661 1 667 1 673 1 678 1 683 1 688 1 692 1 699
87 955 100 000 97 423 86 180 86 367 96 547 86 379 86 517 86 649 100 000 86 618 91 875 86 607 97 466 94 686 100 000 96 541 100 000 100 000 100 000 100 000 100 000
14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14
255 256 258 259 260 261 262 263 263 264 264 265 265 266 266 266 267 267 267 268 268 269
15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
169 164 159 153 145 133 123 118 114 109 106 102 99 96
12 999 12 608 12 194 11 750 11 118 10 185 9 465 9 047 8 708 8 394 8 110 7 853 7 616 7 394
1 706 1 710 1 715 1 719 1 723 1 729 1 731 1 732 1 731 1 729 1 727 1 725 1 723 1 722
100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000
14 14 14 14 14 14 14 14 14 14 14 14 14 14
269 270 270 270 271 271 271 271 272 271 271 271 271 271
Page 108 of 119
Doc. Title:
Basis of Design
Document No.:
YME04-REN-Z-FD-0009
Rev.:
01
Table 15-5 Gamma C2 Producer
15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020
Oil sm3/d 1 931 1 962 1 570 1 590 1 274 1 498
Gamma West C2_AT2 Producer Gas PW Gas Lift sm3/d sm3/d sm3/d 122 747 0 70 000 126 125 0 70 000 101 946 8 70 000 105 562 196 70 000 86 578 343 64 593 105 957 532 66 213
15.03.2020 15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023
1 197 1 013 938 890 824 714 635 559 544 503 504 497 396 403 468 444 386 298 244 318 219 200
83 687 71 764 72 193 75 390 72 379 55 165 45 275 37 607 36 807 33 368 34 196 38 460 27 435 42 424 92 604 51 157 37 456 26 478 20 199 77 217 22 693 20 117
590 643 700 727 740 721 721 708 734 735 784 845 767 851 1 035 972 972 872 817 1 115 928 872
15.07.2023 15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028
181 175 158 154 138 134 133 129 123 122 118 109 104 108 106 98 94 96 96 91 85 88
20 451 19 885 16 968 21 409 18 559 16 367 15 939 22 556 20 269 14 987 16 461 22 294 19 994 13 084 13 876 19 136 19 446 12 334 12 559 17 441 16 988 11 629
15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
89 82 78 82 82 72 67 64 63 65 64 63 62 61
11 848 15 489 14 106 11 037 11 250 13 374 10 505 9 326 8 987 10 528 10 991 10 244 8 816 7 576
Date
THP bar 61 45 50 33 31 16
BHP bar 267 243 239 227 225 218
70 000 70 000 70 000 70 000 67 579 69 344 67 378 61 162 65 382 63 194 70 000 70 000 62 680 63 844 62 262 70 000 70 000 62 764 63 586 70 000 68 462 61 135
14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14
212 211 212 211 209 208 208 207 209 209 213 216 210 210 207 218 222 217 210 211 220 214
811 870 876 856 764 803 850 806 711 763 824 770 674 740 809 751 679 730 787 731 678 725
61 569 70 000 68 196 60 326 60 457 67 583 60 465 60 562 60 654 70 000 60 633 64 312 60 625 68 226 66 280 70 000 67 579 70 000 70 000 70 000 70 000 70 000
14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14
205 212 214 208 198 204 210 200 189 200 206 194 184 198 205 194 185 197 203 192 186 196
770 721 679 722 747 633 574 553 546 553 555 551 552 563
70 000 70 000 70 000 70 000 70 000 70 000 70 000 70 000 70 000 70 000 70 000 70 000 70 000 70 000
14 14 14 14 14 14 14 14 14 14 14 14 14 14
201 192 188 196 199 183 178 177 176 176 176 176 177 180
Page 109 of 119
Doc. Title:
Basis of Design
Document No.:
YME04-REN-Z-FD-0009
Rev.:
01
Table 15-6 Gamma C3 Producer Date
Gamma West C3_T3 Producer PW Gas Lift sm3/d sm3/d 0 70 000 0 70 000 247 70 000 656 70 000 809 64 593 874 66 213
15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020
Oil sm3/d 1 992 2 064 1 476 1 315 923 505
Gas sm3/d 121 338 126 682 92 139 83 649 58 975 30 021
THP bar 62 44 40 17 14 14
BHP bar 268 245 239 227 224 222
15.03.2020 15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023
389 292 162 141 157 216 296 516 413 423 208 226 155 56 25 68 108 144 77 26 141 131
23 174 68 227 81 447 95 669 122 377 153 177 127 457 114 201 76 504 138 798 146 553 304 520 285 521 126 386 57 852 61 336 105 754 338 959 224 908 52 795 174 828 368 751
842 595 306 228 254 347 518 1 042 1 021 1 171 695 660 384 122 50 242 469 526 270 96 788 642
70 000 70 000 0 0 0 0 0 61 162 65 382 63 194 0 0 0 0 0 0 0 0 0 0 0 0
14 40 52 65 67 62 41 14 14 14 49 65 75 81 81 60 57 73 80 70 44 58
219 220 229 230 227 220 215 202 208 205 220 228 218 230 238 243 240 224 221 242 227 215
15.07.2023 15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028
78 92 119 126 94 137 110 130 98 85 133 121 110 69 114 110 100 62 98 97 88 58
262 504 153 786 171 302 405 074 296 527 146 289 181 413 439 385 303 869 53 901 192 989 414 248 324 267 44 772 154 546 367 042 301 959 47 661 130 006 331 743 255 197 49 253
432 676 888 851 678 1 237 1 042 1 159 896 1 011 1 405 1 311 1 155 960 1 344 1 297 1 160 961 1 266 1 262 1 134 965
0 0 0 0 0 67 583 60 465 0 0 70 000 60 633 0 0 68 226 66 280 0 0 70 000 70 000 0 0 70 000
66 47 38 46 49 18 34 29 33 14 14 14 15 14 14 14 14 14 14 14 14 14
211 219 217 205 197 197 209 190 183 199 199 182 172 198 201 183 173 197 200 182 176 196
15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
84 86 72 55 66 75 75 75 74 70 67 62 55 46
102 013 286 493 187 561 51 395 69 526 267 819 307 940 302 852 272 280 244 504 214 694 186 015 146 668 107 484
1 171 1 243 1 039 971 1 051 1 111 1 077 1 051 1 020 993 963 929 825 706
70 000 0 0 70 000 70 000 0 0 0 0 0 0 0 0 0
14 14 14 14 14 14 14 14 14 14 14 14 14 14
200 183 181 195 198 175 169 167 167 167 168 169 172 177
Page 110 of 119
Doc. Title:
Basis of Design
Document No.:
YME04-REN-Z-FD-0009
Rev.:
01
Table 15-7 Gamma C4 Producer Date
Gamma West C4_T3 Producer PW Gas Lift sm3/d sm3/d 1 570 70 000 1 438 70 000 1 350 70 000 1 292 70 000 1 180 64 593 1 052 66 213
15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020
Oil sm3/d 761 622 635 636 358 212
Gas sm3/d 46 608 38 086 38 879 38 903 21 835 12 860
THP bar 14 14 14 14 14 14
BHP bar 274 265 260 256 248 238
15.03.2020 15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023
172 161 159 160 165 226 414 390 394 266 234 159 284 338 123 139 114 117 314 192 132 105
10 398 9 707 9 623 9 657 9 966 14 591 93 636 129 257 149 093 125 409 116 372 34 435 37 692 169 780 119 684 144 057 100 183 13 947 172 091 175 258 115 734 14 881
984 973 973 972 976 1 003 1 257 1 133 1 275 975 924 928 996 1 422 672 871 936 878 1 428 996 1 063 883
70 000 70 000 70 000 70 000 67 579 69 344 67 378 61 162 65 382 63 194 70 000 70 000 62 680 63 844 62 262 70 000 70 000 62 764 63 586 70 000 68 462 61 135
14 14 14 14 14 14 14 23 14 28 31 14 14 14 51 43 30 14 14 36 23 14
233 232 232 231 232 234 223 219 208 210 213 208 220 213 224 219 211 215 213 214 205 214
15.07.2023 15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028
268 109 95 81 203 110 99 77 178 118 83 64 146 114 67 49 113 100 59 46 93 86
176 489 159 521 129 020 12 758 171 501 176 082 124 752 12 570 173 866 237 290 110 538 11 126 162 396 237 561 89 863 9 224 127 566 211 536 79 347 9 347 98 861 186 168
1 450 897 1 039 856 1 454 999 1 168 843 1 471 1 332 1 119 816 1 449 1 413 1 039 782 1 350 1 381 1 013 798 1 270 1 357
61 569 0 68 196 60 326 60 457 0 60 465 60 562 60 654 0 60 633 64 312 60 625 68 226 66 280 70 000 67 579 70 000 70 000 70 000 70 000 70 000
14 29 26 14 14 29 16 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14
212 216 206 212 210 212 197 210 208 199 192 208 207 196 190 205 207 196 190 207 207 196
15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
53 45 70 71 53 50 52 48 47 0 37 34 0 28
70 889 10 554 67 138 154 566 70 911 9 020 10 311 9 285 9 097 0 7 690 6 999 0 5 825
1 000 816 1 140 1 323 1 075 866 898 915 952 0 953 949 0 937
70 000 70 000 70 000 70 000 70 000 70 000 70 000 70 000 70 000 0 70 000 70 000 0 70 000
14 14 14 14 5 14 14 7 14 10 1 2 6 14
191 208 208 197 73 215 218 104 218 162 22 26 95 219
Page 111 of 119
Doc. Title:
Basis of Design
Document No.:
YME04-REN-Z-FD-0009
Rev.:
01
Table 15-8 Gamma C7 Producer Date
Gamma North East C7 Producer PW Gas Lift sm3/d sm3/d 0 0 0 0 152 100 000 218 100 000 291 92 276 315 94 590
15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020
Oil sm3/d 0 0 1 218 1 142 1 010 932
Gas sm3/d 0 0 69 286 64 973 57 440 52 992
THP bar 0 0 21 14 14 14
BHP bar 0 0 185 172 173 173
15.03.2020 15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023
872 823 788 759 736 713 693 674 659 647 638 626 611 596 567 558 554 551 540 535 509 329
49 524 46 690 44 675 42 969 41 642 40 351 39 148 38 100 37 217 36 519 36 014 35 262 34 411 33 545 31 938 31 422 31 194 31 005 30 404 30 166 28 678 18 512
304 306 310 309 307 307 306 309 315 321 327 337 344 350 359 366 375 391 406 420 439 493
100 000 100 000 100 000 100 000 96 542 99 062 96 255 87 374 93 403 90 277 100 000 100 000 89 543 91 205 88 945 100 000 100 000 89 663 90 838 100 000 97 803 87 336
14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14
169 166 164 163 161 160 158 158 157 158 158 158 158 158 158 158 159 161 162 164 165 163
15.07.2023 15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028
277 249 230 216 203 192 184 177 170 163 158 154 150 147 144 142 140 137 135 133 130 127
15 608 14 047 12 957 12 140 11 426 10 834 10 373 9 967 9 551 9 183 8 915 8 683 8 446 8 256 8 138 8 021 7 883 7 743 7 616 7 484 7 335 7 170
521 544 564 580 594 606 619 629 635 642 649 655 659 663 669 676 680 685 691 696 699 702
87 955 100 000 97 423 86 180 86 367 96 547 86 379 86 517 86 649 100 000 86 618 91 875 86 607 97 466 94 686 100 000 96 541 100 000 100 000 100 000 100 000 100 000
14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14
164 166 168 170 171 172 173 174 175 176 177 177 178 178 179 180 180 181 181 182 182 183
15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
124 122 119 116 112 106 101 93 87 83 79 76 73 71
7 004 6 859 6 710 6 532 6 336 5 994 5 700 5 233 4 921 4 668 4 466 4 296 4 143 4 001
706 710 714 720 726 732 739 748 753 756 759 761 764 766
100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000 100 000
14 14 14 14 14 14 14 14 14 14 14 14 14 14
183 184 184 185 185 186 187 188 188 189 189 190 190 190
Page 112 of 119
Doc. Title:
Basis of Design
Document No.:
YME04-REN-Z-FD-0009
Rev.:
01
Table 15-9 Gamma C9 Producer Date
Gamma South West C9 Producer PW Gas Lift sm3/d sm3/d 0 0 0 0 0 0 0 0 0 64 593 0 66 213
15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020
Oil sm3/d 0 0 0 0 1 164 1 191
Gas sm3/d 0 0 0 0 82 386 83 753
THP bar 0 0 0 0 32 14
BHP bar 0 0 0 0 183 149
15.03.2020 15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023
1 022 958 914 872 835 789 730 623 569 543 590 0 375 466 581 361 311 265 277 256 169 196
71 257 66 253 62 799 59 574 56 705 53 304 49 121 41 690 37 955 36 258 42 604 0 34 091 51 761 149 240 165 940 181 445 65 180 29 490 154 030 148 405 74 202
0 0 0 0 0 0 3 43 51 59 68 0 133 150 211 171 166 157 217 233 169 205
70 000 70 000 70 000 70 000 67 579 69 344 67 378 61 162 65 382 63 194 70 000 0 62 680 63 844 62 262 0 0 62 764 63 586 0 0 61 135
14 14 14 14 14 14 14 14 14 14 14 4 14 14 14 14 17 14 14 16 27 3
137 133 130 128 125 122 119 117 115 115 117 32 110 114 106 94 95 92 116 100 111 21
15.07.2023 15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028
205 246 191 158 168 237 162 117 139 206 127 113 111 190 119 106 85 175 117 72 82 168
22 519 157 573 175 365 61 932 16 141 167 648 185 711 34 990 12 628 161 582 193 811 33 004 9 802 151 118 207 651 29 258 7 338 121 182 198 797 14 255 7 359 110 327
250 290 227 204 256 287 212 185 268 274 191 179 266 288 197 180 268 296 213 181 275 303
61 569 0 0 60 326 60 457 0 0 60 562 60 654 0 0 64 312 60 625 0 0 70 000 67 579 0 0 70 000 70 000 0
14 14 18 9 14 14 19 14 14 14 20 14 14 14 19 14 14 14 18 14 14 14
118 101 97 58 119 98 93 92 121 97 92 91 120 99 90 93 120 105 90 98 122 110
15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
117 54 90 144 121 95 111 106 101 96 90 86 83 79
181 296 11 528 9 089 91 917 157 607 11 051 12 045 11 554 10 620 10 592 10 195 9 782 9 369 8 991
231 198 279 285 259 287 317 325 353 364 369 373 377 379
0 70 000 70 000 0 0 70 000 70 000 70 000 70 000 70 000 70 000 70 000 70 000 70 000
16 14 14 14 14 14 14 14 14 14 14 14 14 14
90 104 122 115 90 122 128 129 134 136 136 137 138 139
Page 113 of 119
Doc. Title:
Basis of Design
Document No.:
YME04-REN-Z-FD-0009
Rev.:
01
Table 15-10 Gamma WAG and Water Injector Well Profiles Date 15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020
Gamma West C5 WAG Injector Gas Water THP sm3/d sm3/d bar 0 1 642 124 0 1 612 124 0 1 631 124 0 1 655 124 0 1 681 124 0 1 725 125
BHP bar 450 450 450 450 450 450
Gamma West C6 WAG Injector Gas Water THP sm3/d sm3/d bar 468 502 0 181 471 561 0 158 463 620 0 148 471 019 0 143 481 693 0 139 490 064 0 137
BHP bar 351 327 314 308 303 300
Gamma East C8 Water Inj. Water THP BHP sm3/d bar bar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
15.03.2020 15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023
477 320 494 845 494 845 494 845 494 845 494 845 0 0 0 0 0 494 845 494 845 494 845 0 0 0 494 845 494 845 0 0 494 845
0 0 0 0 0 0 1 065 1 289 1 418 1 407 1 218 0 0 0 1 167 1 265 1 416 0 0 1 384 1 664 0
194 185 180 177 175 172 58 71 80 78 61 163 162 156 49 56 70 158 155 64 89 156
367 356 351 348 345 342 385 397 406 404 387 333 331 324 375 382 396 326 323 390 414 324
0 0 0 0 0 0 494 845 494 845 466 810 494 845 494 845 0 0 0 494 845 494 845 494 845 0 0 494 845 494 845 0
1 517 1 390 1 199 1 123 1 160 1 247 0 0 0 0 0 1 142 1 272 1 511 0 0 0 1 344 1 617 0 0 1 459
17 13 4 -1 -1 2 139 134 131 130 129 -4 -5 11 140 138 137 4 13 136 134 -1
341 337 328 323 324 326 303 296 292 291 290 321 319 334 304 302 301 327 336 299 296 323
1 978 1 858 1 806 1 845 1 914 1 976 2 599 2 842 2 913 2 833 2 599 2 691 2 460 2 523 2 340 2 554 2 727 2 751 2 826 2 815 2 925 2 773
37 32 27 25 25 26 50 63 69 69 61 59 56 60 57 64 74 79 85 87 96 92
361 358 352 350 350 351 370 381 387 388 381 379 378 381 379 384 393 398 404 406 414 411
15.07.2023 15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028
494 845 0 0 494 845 494 845 0 0 494 845 494 845 0 0 459 663 494 845 0 0 398 769 429 696 0 0 342 136 346 701 0
0 1 592 1 767 0 0 2 054 1 947 0 0 2 120 2 124 0 0 2 155 2 074 0 0 2 200 2 061 0 0 2 231
153 83 104 155 151 119 115 153 149 125 125 148 146 124 116 141 139 126 115 137 132 128
321 408 429 323 319 442 439 321 316 447 447 315 312 447 439 306 303 448 438 301 295 450
0 494 845 494 845 0 0 494 845 494 845 0 0 449 135 494 845 0 0 423 052 441 777 0 0 364 547 391 759 0 0 323 707
1 776 0 0 1 582 1 909 0 0 1 723 2 026 0 0 1 820 2 138 0 0 1 848 2 136 0 0 1 882 2 175 0
17 130 126 2 17 125 122 3 15 117 120 3 16 113 116 3 17 109 112 3 20 105
339 291 286 324 338 284 281 325 335 275 278 324 336 270 274 325 336 265 268 324 339 261
2 734 2 725 2 726 2 730 2 732 2 729 2 731 2 723 2 720 2 720 2 722 2 724 2 724 2 724 2 726 2 726 2 724 2 722 2 720 2 714 2 704 2 694
91 93 94 96 98 99 100 101 102 103 103 104 105 105 105 106 106 106 106 106 106 105
411 412 414 416 418 419 420 421 422 422 423 424 424 425 425 425 426 426 426 426 426 425
15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
0 288 443 241 714 0 0 0 0 0 0 0 0 0 0 0
2 073 0 0 2 246 2 163 1 976 1 929 1 922 1 984 1 332 2 009 2 016 1 356 2 000
116 132 124 128 88 126 125 94 122 111 79 81 95 122
439 295 286 450 413 450 449 420 446 436 405 407 421 446
331 600 0 0 265 342 264 893 255 591 294 107 285 441 252 756 216 829 194 290 163 333 114 757 79 417
0 1 955 2 164 0 0 0 0 0 0 0 0 0 0 0
106 7 21 102 99 85 80 78 76 75 74 73 73 73
262 328 340 258 254 234 228 224 222 221 219 218 218 218
2 691 2 690 2 688 2 688 2 683 2 673 2 664 2 658 2 649 2 640 2 632 2 625 2 618 2 613
105 105 105 105 105 104 104 103 102 101 100 99 99 98
425 425 425 425 425 425 424 423 422 421 421 420 419 419
Page 114 of 119
Doc. Title:
Basis of Design
Document No.:
YME04-REN-Z-FD-0009
Rev.:
01
Table 15-11 Beta D-1H Producer Date
Beta East D-1H Producer PW Gas Lift sm3/d sm3/d 27 16 000 30 16 000 31 16 000 37 16 000 73 73 821 138 75 672 261 80 000
15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020 15.03.2020
Oil sm3/d 1 406 1 401 1 423 1 328 1 488 1 259 895
Gas sm3/d 75 723 74 923 75 888 70 617 78 993 66 853 47 650
15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023 15.07.2023
691 606 561 306 349 354 353 347 340 330 302 293 268 252 241 232 221 212 203 205 193 185
36 32 913 414 30 001 16 335 18 685 18 921 18 856 18 576 18 180 17 662 16 187 15 709 14 399 13 568 12 975 12 509 11 952 11 446 10 995 11 067 10 468 10 040
369 420 451 294 337 354 368 380 391 401 411 452 470 483 494 503 515 525 532 561 561 564
15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028 15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
179 182 176 171 167 162 159 155 152 150 148 145 143 142 140 138 137 135 134 133 131 130 129 128 126 120 113 141 131 125 121 118 115 113 111
9 9 682 848 9 551 9 290 9 048 8 826 8 627 8 441 8 284 8 145 8 019 7 900 7 794 7 695 7 602 7 511 7 430 7 353 7 281 7 209 7 140 7 074 7 008 6 940 6 867 6 498 6 151 7 660 7 083 6 797 6 571 6 394 6 242 6 113 5 994
568 598 600 602 603 604 604 604 604 604 604 604 604 604 603 603 603 602 602 601 600 600 599 599 598 578 567 691 666 658 655 654 653 652 651
THP bar 63 44 33 27 34 32 32
BHP bar 290 264 245 233 216 206 198
80 80 000 000 80 000 53 098 54 484 52 940 48 056 51 372 49 653 55 000 53 000 62 680 63 844 62 262 70 000 70 000 62 764 63 586 70 000 78 242 69 868 70 364
29 29 28 46 40 39 38 37 37 36 35 39 38 38 37 37 36 36 36 37 37 36
193 193 193 216 215 215 215 214 214 214 214 210 210 210 210 210 210 210 210 207 206 206
80 85 000 246 75 407 75 571 84 479 75 581 75 702 75 818 87 500 75 791 80 390 75 781 85 283 82 851 87 500 84 474 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500 87 500
36 37 37 37 37 37 37 38 38 38 38 38 38 39 39 39 39 39 40 40 40 40 40 41 41 37 33 26 26 26 26 25 25 25 25
206 205 205 205 206 206 206 206 206 207 207 207 208 208 208 209 209 209 209 210 210 210 211 211 211 207 203 191 187 185 184 184 183 183 183
Page 115 of 119
Doc. Title:
Basis of Design
Document No.:
YME04-REN-Z-FD-0009
Rev.:
01
Table 15-12 Beta D-2H Producer Date
Beta East D-2H Producer PW Gas Lift sm3/d sm3/d 3 14 000 7 14 000 29 14 000 51 14 000 93 64 593 148 66 213 258 70 000
15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020 15.03.2020
Oil sm3/d 1 542 1 548 1 525 1 327 1 449 1 243 906
Gas sm3/d 81 784 81 967 80 701 70 139 76 535 65 726 47 956
15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023 15.07.2023
674 583 521 252 293 296 291 283 275 265 260 250 230 215 203 192 178 166 157 170 158 150
35 30 693 900 27 641 13 358 15 563 15 736 15 469 15 046 14 589 14 089 13 856 13 289 12 221 11 454 10 802 10 224 9 511 8 876 8 369 9 095 8 437 8 022
390 450 494 273 321 341 358 372 384 396 429 468 486 500 513 524 539 551 558 635 635 638
15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028 15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
143 136 131 126 122 117 113 109 105 100 96 91 87 83 79 76 73 71 68 66 64 62 60 58 57 54 50 70 65 62 60 58 56 54 53
7 7 659 277 6 983 6 731 6 497 6 271 6 052 5 820 5 596 5 362 5 122 4 867 4 642 4 434 4 247 4 068 3 915 3 775 3 650 3 524 3 412 3 307 3 213 3 117 3 032 2 867 2 662 3 722 3 467 3 320 3 186 3 077 2 981 2 898 2 817
646 650 654 657 660 662 663 665 666 667 668 669 670 671 672 673 673 674 674 674 675 675 675 676 676 647 633 785 746 735 731 729 728 728 728
THP bar 69 45 33 27 34 32 32
BHP bar 299 270 250 237 221 212 205
70 70 000 000 70 000 43 444 44 578 43 315 39 318 42 031 40 625 45 000 47 000 53 726 54 723 53 367 60 000 60 000 53 798 54 503 60 000 73 352 65 502 65 967
29 29 28 46 40 39 38 37 37 36 35 39 38 38 37 37 36 36 36 37 37 36
202 203 205 222 223 224 224 224 224 224 223 222 222 222 222 223 223 223 224 221 219 219
75 73 000 068 64 635 64 775 72 410 64 784 64 888 64 987 75 000 64 964 68 906 64 955 73 100 71 015 75 000 72 406 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000 75 000
36 37 37 37 37 37 37 38 38 38 38 38 38 39 39 39 39 39 40 40 40 40 40 41 41 37 33 26 26 26 26 25 25 25 25
219 220 221 221 222 222 223 223 223 224 224 225 225 226 226 226 227 227 228 228 229 229 229 230 230 227 224 211 205 203 202 202 202 202 202
Page 116 of 119
Doc. Title:
Basis of Design
Document No.:
YME04-REN-Z-FD-0009
Rev.:
01
Table 15-13 Beta North Producer Date
Beta North Producer PW Gas Lift sm3/d sm3/d 0 0 0 0 0 0 0 0 0 0 0 0 0 0
15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020 15.03.2020
Oil sm3/d 0 0 0 0 0 0 0
Gas sm3/d 0 0 0 0 0 0 0
15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023 15.07.2023
0 0 0 2 391 2 090 1 855 1 683 1 541 1 426 1 321 1 142 1 120 996 868 782 704 586 489 451 399 328 278
0 0 0 153 384 134 715 119 787 108 713 99 468 91 980 85 202 73 810 72 302 64 215 55 980 50 399 45 336 37 708 31 447 28 954 25 631 21 222 18 052
0 0 0 87 148 212 264 312 353 387 452 564 616 671 713 755 823 882 914 900 955 1 001
15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028 15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
249 222 208 197 188 179 172 165 159 154 149 144 140 136 132 127 123 120 116 113 110 108 106 104 102 105 108 0 0 0 0 0 0 0 0
16 14 128 433 13 530 12 813 12 200 11 666 11 187 10 740 10 361 10 019 9 714 9 411 9 142 8 871 8 612 8 327 8 056 7 808 7 584 7 365 7 186 7 034 6 905 6 786 6 675 6 853 7 091 0 0 0 0 0 0 0 0
1 1 042 063 1 104 1 142 1 179 1 216 1 253 1 292 1 328 1 367 1 409 1 452 1 493 1 534 1 574 1 615 1 654 1 692 1 730 1 769 1 804 1 839 1 872 1 907 1 941 2 016 2 113 0 0 0 0 0 0 0 0
THP bar 0 0 0 0 0 0 0
BHP bar 0 0 0 0 0 0 0
0 0 0 48 271 49 531 48 127 43 687 46 702 45 139 50 000 50 000 80 589 82 085 80 051 90 000 90 000 80 696 81 754 90 000 83 133 74 235 74 762
0 0 0 50 42 41 40 39 39 38 37 41 40 40 39 39 38 38 38 39 39 38
0 0 0 297 277 269 264 261 258 256 254 250 248 247 247 247 247 248 250 252 255 257
85 80 000 374 71 098 71 253 79 651 71 262 71 376 71 485 82 500 71 460 75 796 71 451 80 410 78 116 82 500 79 646 82 500 82 500 82 500 82 500 82 500 82 500 82 500 82 500 82 500 82 500 82 500 0 0 0 0 0 0 0 0
38 39 39 39 39 39 39 40 40 40 40 40 40 41 41 41 41 41 42 42 42 42 42 43 43 31 18 0 0 0 0 0 0 0 0
260 264 268 272 275 279 282 286 289 293 296 299 302 306 309 312 315 318 321 323 326 329 331 334 336 240 140 0 0 0 0 0 0 0 0
Page 117 of 119
Doc. Title:
Basis of Design
Document No.:
YME04-REN-Z-FD-0009
Rev.:
01
Table 15-14 Beta East and Beta North Water Injectors Date 15.09.2019 15.10.2019 15.11.2019 15.12.2019 15.01.2020 15.02.2020 15.03.2020
Beta East D-3H Water Injector Water THP BHP sm3/d bar bar 30 -15 348 37 -31 331 61 -46 317 89 -57 305 166 -64 298 286 -67 295 519 -60 302
Beta North Water Injector Water THP BHP sm3/d bar bar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
15.04.2020 15.05.2020 15.06.2020 15.07.2020 15.08.2020 15.09.2020 15.10.2020 15.11.2020 15.12.2020 15.01.2021 15.03.2021 15.05.2021 15.07.2021 15.09.2021 15.11.2021 15.01.2022 15.04.2022 15.07.2022 15.10.2022 15.01.2023 15.04.2023 15.07.2023
760 871 945 135 162 179 193 205 215 225 244 278 293 307 319 330 347 363 372 391 407 421
-43 -33 -26 -73 -73 -71 -70 -68 -67 -66 -65 -62 -61 -60 -59 -58 -56 -55 -54 -53 -53 -53
319 329 336 289 289 291 292 294 295 296 297 300 301 302 303 304 306 307 308 309 309 309
0 0 0 519 644 728 798 859 912 959 1 049 1 205 1 279 1 347 1 402 1 452 1 530 1 596 1 633 1 704 1 744 1 782
0 0 0 -33 -47 -54 -59 -62 -64 -66 -68 -70 -71 -72 -72 -72 -71 -69 -67 -65 -61 -58
0 0 0 330 315 308 304 300 298 296 294 291 289 288 288 288 289 290 292 294 298 301
15.10.2023 15.01.2024 15.04.2024 15.07.2024 15.10.2024 15.01.2025 15.04.2025 15.07.2025 15.10.2025 15.01.2026 15.04.2026 15.07.2026 15.10.2026 15.01.2027 15.04.2027 15.07.2027 15.10.2027 15.01.2028 15.04.2028 15.07.2028 15.10.2028 15.01.2029 15.04.2029 15.07.2029 15.10.2029 15.01.2030 15.07.2030 15.01.2031 15.07.2031 15.01.2032 15.07.2032 15.01.2033 15.07.2033 15.01.2034 15.07.2034
432 445 458 471 483 496 508 521 534 548 562 577 591 605 620 635 649 664 678 693 707 721 734 749 763 860 918 387 401 417 435 455 477 500 525
-51 -49 -48 -47 -46 -45 -44 -43 -42 -41 -40 -39 -38 -37 -35 -34 -33 -32 -31 -30 -29 -27 -26 -25 -24 -30 -39 -62 -69 -70 -70 -69 -68 -67 -66
312 313 314 315 316 317 318 319 320 321 322 323 325 326 327 328 329 330 332 333 334 335 336 337 338 332 323 300 293 292 292 293 293 295 296
1 1 824 866 1 900 1 930 1 959 1 986 2 013 2 040 2 064 2 091 2 119 2 149 2 176 2 203 2 229 2 256 2 281 2 305 2 328 2 351 2 372 2 393 2 412 2 433 2 453 2 381 2 394 1 088 1 011 976 951 928 904 880 854
-54 -50 -46 -42 -38 -34 -30 -26 -22 -18 -14 -10 -6 -3 1 4 8 11 14 18 21 24 27 30 32 35 41 54 69 83 96 109 122 135 147
305 309 313 317 321 325 329 333 336 340 344 348 351 355 358 362 365 369 372 375 378 381 384 387 389 394 401 417 432 446 460 474 487 500 512
Page 118 of 119
Doc. Title:
Basis of Design
Document No.:
YME04-REN-Z-FD-0009
Rev.:
01
Page 119 of 119
